CCUS Role in the Transition to Net-Zero: Part 4

Issues for Successful Deployments

By Abigael Eminza and Claudia Nyon

Successful deployment of Carbon Capture, Utilisation and Storage (CCUS) depends not only on technology but also on coherent policy, law, and financial frameworks. Countries like Norway demonstrate that a strong business case, reinforced by carbon pricing and regulatory certainty, is essential to make CCUS cost-competitive and attractive for private investment. At the international level, instruments such as the London Protocol govern cross-border CO2 transport, though gaps remain, particularly in ASEAN and other emerging markets. Fiscal measures, including subsidies, tax incentives, and revenue guarantees, can help overcome the reluctance of businesses to be first movers in new CCS hubs. This section examines the legal, financial, and policy levers required to scale CCUS while highlighting both the potential benefits and inherent challenges.

National Policy and Laws 

Robust legal frameworks underpin successful CCUS deployment, ensuring that technology can translate into real-world emission reductions. Norway demonstrates how a strong policy environment, anchored by carbon pricing, can make CCUS commercially viable. The Sleipner project, often cited as the world’s first large-scale CCS facility, was made possible by the Norwegian carbon tax on offshore oil and gas, which created a compelling business case for investment (Global CCS Institute). This shows how fiscal levers, such as targeted taxes, incentives, or revenue guarantees, can help overcome market reluctance, especially where pure economic returns are uncertain.

Globally, a persistent challenge lies in the mismatch between planned capture capacity and available storage. Without regulatory certainty, private actors are often reluctant to invest, highlighting the importance of laws that guarantee long-term access and clearly define liability arrangements for CO2 storage (Global CCS Institute). International frameworks, such as the London Protocol, guide cross-border CO2 transport, but limited ratification, particularly in ASEAN and other emerging markets, continues to restrict regional deployment. Bilateral or multilateral agreements may serve as interim solutions, yet broader harmonization is needed to reduce legal uncertainty and enable large-scale projects.

Some countries are beginning to experiment with domestic CCUS legislation. For example, Sarawak enacted a law in 2024 to promote CCUS projects, representing one of the first attempts in ASEAN to integrate CCUS into national energy transition pathways (Laws of Sarawak, 2024). Such legislation must be aligned with international commitments, including the Paris Agreement, to ensure consistency and attract private investment. In addition, developing robust regional standards for measurement, reporting, and verification (MRV) is essential to provide credible, transparent assessments of greenhouse gas reductions (Havercroft et al., 2024; World Bank Group, 2022).

Effective CCUS regulation also requires clearly defined processes and obligations throughout the entire project lifecycle. From planning and exploration to operation, closure, and post-closure, operators must obtain authorisations at key milestones, ensuring accountability and regulatory oversight at every stage (Havercroft et al., 2024). Establishing such frameworks helps create confidence for investors, protects the environment, and provides a predictable pathway for scaling CCUS while balancing technical, financial, and legal considerations.

Hefty CCUS investment is needed globally

Global CCUS deployment requires substantial investment. US$196 billion will be needed through 2034 to support planned CCUS projects worldwide (Wood Mackenzie, 2024).To mobilise this level of funding, a combination of financial and policy mechanisms is critical. Key instruments that can attract private investment and reduce early-stage risks include:

• Fiscal incentives: This would allow for private finance as “The only means by which a positive return on investment in CCS is achieved is when the service provided by CCS (CO2 emissions abatement) is monetised” (Global CCS Institute, 2021). Incentives, such as subsidies, tax credits, and price support mechanisms, can bridge the gap between technical feasibility and commercial viability (McKinsey & Company, 2022).

• Tax measures: Targeted tax policies, exemplified by the Sleipner project in Norway, demonstrate how carbon taxation can create a robust business case for investment in CCUS infrastructure, effectively reducing financial risk and encouraging uptake (Global CCS Institute, 2021).

• Revenue guarantees: Initial investment in CCS hubs and clusters is hindered by first-mover risk. Businesses prefer mature networks where financial returns are more predictable (Williams et al., 2024). Guarantees of revenue or offtake agreements during early project stages can lower this barrier, enabling governments to play a pivotal role in catalysing private sector participation.

Cross-border issues, London Protocol

Several international treaties and protocols provide a legal and regulatory framework relevant to CCUS, particularly for offshore storage and cross-border operations. The London Protocol (2009 amendment) and its predecessor, the London Convention (1972), govern the sub-seabed injection and transboundary transport of CO2 while protecting the marine environment. UNCLOS (1982) establishes general obligations for offshore environmental protection, and the Convention on Biological Diversity (1992) ensures that CCUS activities avoid harming marine ecosystems. The Paris Agreement (2015) sets climate targets that drive CCUS deployment within national mitigation strategies, while IMO regulations oversee the safe maritime transport of captured CO2. Collectively, these instruments provide a patchwork of environmental, safety, and climate obligations, highlighting the need for coordination between international law and national regulations to enable large-scale, legally compliant CCUS projects.

More on the Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter 1972 (or the London Protocol). 

Originally designed for waste management, the London Protocol entered into force on 24 March 2006 and had 54 contracting parties as of September 2023. Article 6 prohibits contracting parties from allowing the export of wastes into the sea, which has been interpreted to include carbon and its cross-border transfer for sub-seabed storage. In response, the Protocol was amended in 2009 to allow cross-border transportation of CO2 for sub-seabed storage, although this amendment has not yet been ratified by two-thirds of contracting parties. It has been suggested that contracting parties could enable transboundary CO2 export through separate treaties (International Energy Agency, 2011).

Despite these legal adjustments, the Protocol provides only a partial framework for CCUS. It establishes environmental safeguards and clarifies responsibilities, which reduces regulatory uncertainty and gives investors greater confidence to develop large-scale CCS hubs. However, its effectiveness is constrained by incomplete ratification, limited adoption in regions such as ASEAN, and its original focus on waste management, leaving gaps in areas like long-term monitoring, liability, and post-closure obligations. To fully enable deployment, countries often need additional national regulations or bilateral agreements, meaning the Protocol serves as a foundational framework rather than a complete solution for international CCUS expansion (International Energy Agency, 2011).

Opportunities and limits of EOR and retrofitting

Enhanced Oil Recovery (EOR) can potentially legitimize continued oil consumption and lower prices. Policy support, such as financial incentives for CO2 stored, should be strictly limited to cases where:

• The combination of the CO2 source and carbon intensity of injection delivers zero or negative net emissions.

• Captured CO2 is used productively, while EOR using mined CO2 is never supported and ideally discouraged.

• Overall, oil demand is constrained by ambitious decarbonisation policies applied across end-use sectors.

New technologies and improvements are under development for post-combustion, pre-combustion, and oxy-fuel combustion capture systems. It remains unclear which CO2 capture technologies will be the most effective in delivering cost reductions and performance improvements, as several are still in the early stages of development and demonstration (IEA, 2020).

Retrofitting existing coal-fired power plants is expensive, technically challenging, and comes with a significant energy ‘penalty’, the extra energy required to power capture operations. Economic sustainability of post-combustion retrofits should be compared on a portfolio basis to CCS on new-build plants, where energy efficiency can be optimised and sequestration sites strategically selected (Hardisty et al., 2011).

CO2 currently lacks sufficient intrinsic market value to make projects economically viable without subsidies. Globally, carbon is largely treated as a waste product with limited commercial value or cascading uses (McLaughlin et al.,2023). National carbon pricing is often absent or insufficient, and public intervention is needed to treat carbon removal as a public good. Effective policies must combine strong government funding, financial incentives, and regulatory frameworks to drive innovation, scale-up, and cost reductions.

Promising developments are emerging in voluntary carbon markets. In 2022, these markets began differentiating by activity type, with carbon removal projects commanding the highest value (Ulucak et al., 2019). The average carbon credit price for carbon removal (~$20/tCO₂) was more than twice that for nature-based removal (~$10/tCO₂) and about four times that for renewable energy offsets (~$5/tCO₂) (McLaughlin et al.,2023).

Source: Hardisty et al., 2011

Key findings: Scaling CCUS requires an integrated approach combining technology, policy, and finance. Countries with supportive regulatory frameworks and financial incentives, such as Norway, demonstrate higher feasibility and investor confidence. However, economic viability is constrained by high retrofitting costs, low CO₂ market value, and technological uncertainty. To achieve meaningful climate impact, governments must provide robust incentives, clear legal frameworks, and credible carbon pricing to enable CCUS projects to move beyond demonstration to large-scale deployment.

In this series:

• Part 1: Climate Mitigation and the Price of CCUS

• Part 2: Case Studies

• Part 3: Malaysia’s Big Ambitions 

• Part 4: Issues for Successful Deployments

Reach us at khorreports[at]gmail.com

CCUS Role in the Transition to Net-Zero: Part 3

Malaysia’s Big Ambitions

By Abigael Eminza and Claudia Nyon

Carbon Capture, Utilization, and Storage (CCUS) has advanced from pioneering offshore projects like Sleipner in Norway to massive new ventures such as Malaysia’s Kasawari development. Sleipner, which began injecting CO2 in 1996, proved that offshore saline aquifer storage was technically feasible, providing decades of operational experience and extensive monitoring data.

Building on this foundation, Malaysia is attempting to commercialize CCS at a scale never before attempted, with Kasawari’s offshore platform designed to process and inject 3.3 million tonnes of CO2 annually from gas with 40% CO2 content. The project is four to five times larger than Sleipner’s, signaling both ambition and unprecedented technical challenges. Together with other announced CCS hubs, Malaysia is positioning itself as a regional leader in carbon storage despite the absence of a dedicated regulatory framework.

The table below shows the differences between the Sleipner project in Norway and the Kasawari project in Malaysia.

IEEFA has compared Sleipner to Malaysia’s CCUS hubs, which are larger by factors of 10 or more. As IEEFA states, “Every proposed project needs to budget and equip itself for contingencies both during and long after operations have ceased” (IEEFA, 2023).

Against this backdrop, Petronas, Malaysia’s national oil and gas company, approved the Kasawari project in November 2022. The project aims to inject 3.3 mtpa of CO₂ underground to monetize a subsea gas deposit with an unusually high CO₂ content of 40%  (IEEFA, 2023).

Located in the South China Sea, 180 km north of Bintulu, Sarawak, the Kasawari CCS project draws gas from the SK316 block, which contains an exceptionally high 40% CO2 content. This concentration creates an unprecedented challenge: stripping out, transporting, and storing such a vast volume of CO₂.

To address this, Kasawari’s RM4.5 billion (US$1 billion) CCS component will include the world’s largest offshore CO2 processing platform. With a planned injection capacity of 3.3 mtpa, it will rank among the largest projects globally, second only to Chevron’s underperforming Gorgon project in Australia, at 3.5 to 4 mtpa.

The scale of Kasawari makes system integrity, injection well performance, and storage reliability absolutely critical if long-term CO2 reduction goals are to be achieved. Yet Malaysia has not established CCS regulations, leaving projects of this magnitude to advance without a dedicated regulatory framework.

This lack of precedent is not unique to Malaysia. Globally, governments and industry are proposing CCS storage sites with capacities far beyond those of Sleipner and Snøhvit. The reality is that projects of the scale envisioned for the Houston Ship Channel, the UK CCS clusters, Norway’s Northern Lights, or Malaysia’s Kasawari have never before been attempted.

In this context, Petronas has opted for a Sleipner-like model, performing all gas processing and CO2 recompression offshore on a dedicated platform. However, unlike Sleipner, Kasawari’s platform and equipment will be four to five times larger, making it the world’s biggest dedicated CO2 processing facility.

The unprecedented size and complexity of Kasawari also extend to its contracting strategy. To manage the project’s unique conditions, massive scale, and the risks, both known and unknown, associated with start-up and commissioning, Petronas has adopted an “alliance contracting” risk-sharing structure with Malaysia Marine and Heavy Engineering. While this conservative approach provides a safeguard against unforeseen challenges, it will likely add to the cost of what is already an RM4.5 billion (US$1 billion) component of the overall development.

Malaysia has recently been pivoting itself as being amenable to CCUS facilities being built in the country. 

By late 2024, four landmark CCUS projects have been announced:

• Petronas Carigali Kasawari-M1: Located offshore Sarawak, the project is scheduled to begin operations in 2026. It is proposed that 60% of the storage capacity will be allocated to Malaysia, for PETRONAS and its partners, with the remaining 40% made available to other users (NS Energy, 2023; Havercroft et al., 2024). 

• PTTEP’s Lang Lebah-Golok: Located offshore Sarawak, the project is scheduled for operation in 2028. Identified as Malaysia’s second CCS project, the Lang Lebah field holds an estimated 5 trillion cubic feet of gas in place. Development will require the removal of both CO2 and hydrogen sulphide (H2S) (Battersby, 2022).

• BIGST Cluster: Estimated to hold around 4 trillion cubic feet of recoverable gas. The cluster has remained undeveloped, however, due to its high CO2 content. Given its strategic role in Peninsular Malaysia’s energy security, development will hinge on carbon capture and storage (CCS), positioning it as the first CCS project in the region (Searancke, 2024; Petronas, 2022).

• M3 Project: Located offshore Sarawak, East Malaysia. The project is designed to store CO₂ emissions from multiple industries in Japan, including those in the Setouchi region, through injection into offshore Sarawak reservoirs (Battersby, 2024).

According to Malaysia’s National Energy Transition Roadmap (NETR), the following CCUS-related targets have been stated. 

By 2030: 

• Develop 3 CCUS hubs (2 in Peninsular Malaysia, 1 in Sarawak) with a total storage capacity up to 15 mTpa (15 million tonnes per annum, mTpa), about 300,000 barrels per day (bpd).

By 2050: 

• Develop 3 carbon capture hubs with a total storage capacity between 40 to 80 mTpa.

A CCUS bill was planned to be tabled by November 2024, and was pushed forward a few months later. Malaysia’s Carbon Capture, Utilisation and Storage (CCUS) Bill 2025 has cleared both houses of Parliament and now awaits Royal Assent, with supporting regulations slated to come into force by March 2025 (The Edge Malaysia, 2025; Malaymail, 2025). Championed by Economy Minister Rafizi Ramli, who has positioned himself as the government’s lead architect on industrial decarbonisation, the bill is designed to unlock investment, regulate offshore CO₂ storage, and lay the groundwork for a carbon tax in 2026. Rafizi has argued that Malaysia cannot rely on reforestation alone and must instead leverage its vast depleted reservoirs and offshore capacity to host large-scale CO₂ storage. By providing a legal framework and clear incentives, the bill seeks to position Malaysia as a regional hub for CCUS, attract foreign investment, and generate new revenue streams through state taxes, port fees, and industrial partnerships.

Petronas is pressing ahead with its decarbonisation strategy following the passage of Malaysia’s CCUS Bill 2025, with the flagship Kasawari CCS project now in production and preparing to capture and inject up to 3.3 million tonnes of CO2 annually into the M1 field offshore Sarawak (Lee, 2025). To deliver this, Petronas awarded a RM4.5 billion EPCIC contract to Malaysia Marine and Heavy Engineering (MMHE) in August 2025 for the construction of the world’s largest offshore CO2 processing platform, located about 138 km from shore (The Edge Malaysia, 2022). The platform will be central to Malaysia’s ambition to become a regional CCUS hub, offering storage services beyond domestic demand.

Key findings: Sleipner demonstrated the technical viability of offshore storage but also highlighted the uncertainties of long-term containment, lessons that are highly relevant for Malaysia’s next-generation projects. Kasawari’s scale makes it a global test case for whether CCS can manage very high CO₂ concentrations and sustain multi-million-tonne annual injections. Yet, regulatory gaps, cost escalation risks, and system integrity concerns cast uncertainty over its long-term effectiveness. Malaysia’s broader CCUS roadmap shows strong ambition, but success will hinge on robust oversight and the ability to manage risks at scales far beyond what has been proven to date.

Editor’s Note: After losing the Parti Keadilan Rakyat (PKR) deputy presidency to Nurul Izzah Anwar in May 2025, Rafizi submitted his resignation as Economy Minister, effective 17 June 2025. Prior to his departure, he had already completed major tasks like the 13th Malaysia Plan. He is considered to be the key mover of the Bill, making CCUS a high priority.

Worth noting: The debate over CCUS in Malaysia was marked by a division between government-backed initiatives and civil society opposition. The government views CCUS as a key part of its National Energy Transition Roadmap, aiming to position Malaysia as a regional lead in carbon management and kick-starting lots of capital expenditure. State-owned energy company Petronas actively pursues offshore CCS projects, collaborating with international partners like ADNOC and Storegga to enhance CO2 storage capacity (The Edge Malaysia, 2022). But, environmental organizations and opposition lawmakers express significant concerns. Groups such as Greenpeace Malaysia and Sahabat Alam Malaysia (SAM) argue that the CCUS Bill was hastily passed without adequate public consultation, questioning its environmental and social implications (Greenpeace Malaysia, 2025). Furthermore, the Borneo states of Sarawak and Sabah have pushed back on the federal CCUS Bill, seeking more control over CCS projects within their territories.

In this series:

• Part 1: Climate Mitigation and the Price of CCUS

• Part 2: Case Studies

• Part 3: Malaysia’s Big Ambitions 

• Part 4: Issues for Successful Deployments

Reach us at khorreports[at]gmail.com

CCUS Role in the Transition to Net-Zero: Part 2

Case Studies

By Claudia Nyon and Abigael Eminza

Carbon Capture, Utilization, and Storage (CCUS) has long been promoted as a critical technology for reducing emissions from fossil fuels while supporting energy security. Over the past three decades, several high-profile projects have attempted to demonstrate the feasibility of capturing CO2 at scale and storing it underground. Some, such as Petra Nova in Texas and Sleipner in the North Sea, have demonstrated that capture and storage can be effective under the right conditions, providing valuable data and technical proof of concept. Others, however, such as Kemper County, Gorgon, and Boundary Dam, have struggled with spiraling costs, underperformance, and technical failures. Taken together, these projects reveal both the promise and the fragility of CCUS as a climate solution.

Source: Energy Transitions Commission

Success stories

The Petra Nova project in the US

Designed to capture approximately 90% of carbon dioxide from a power plant and inject it into an oil field to boost crude oil production, the Petra Nova project was completed on time and within budget (Dubin, 2017). The system diverts about 37% of the coal power plant’s emissions through a flue gas slipstream, capturing roughly 33% of total emissions, and requires a dedicated natural gas unit to meet the energy-intensive demands of the carbon-capture process. Captured CO2 is then injected into nearby oil fields for enhanced oil recovery, a process that increases crude oil flow by injecting CO2, water, or chemicals into reservoirs.

Although the project shut down during COVID-19 due to low oil prices (Dilon & Anchondo, 2020), it has been operating since 2023 (Power Engineering, 2023) after being bought by JX Nippon in 2022. 

Sleipner, the world’s first commercial CCUS project.

The Sleipner project began CO2 injection in 1996 in response to Norway’s early-1990s carbon tax, which made carbon capture more profitable than just separating the carbon and releasing it into the atmosphere. This was particularly important because the gas contained about 9% CO2, above market specifications (Dickson, 2024). By 2016, Sleipner had reached its 20-year milestone, with 16 million tons of CO2 stored in the Utsira sandstone formation, located 800 meters beneath the seabed (Skalmeras, 2017).

Storing carbon underground is not an exact science, making Sleipner one of the most studied geological fields worldwide, with over 150 academic papers published (IEEFA, 2023). Their seismic datasets have been downloaded more than a thousand times. 

Despite the studies, long-term stability remains uncertain. In 1999, three years after Sleipner began storage, CO2 had already migrated from its injection point to the top of the formation and into a previously unidentified shallow layer. Large amounts accumulated there, and if the layer had not been sealed, the CO2 might have escaped (IEEFA, 2023). 

Rather than serving as models for CCS expansion, Sleipner and Snøhvit, another Norwegian project, raise doubts about whether sufficient capability, oversight, and sustained investment exist to keep CO2 securely stored beneath the sea permanently.

Failures 

The Kemper project

The Kemper project was initially designed to capture approximately 65% of the plant’s CO2 using pre-combustion technology. However, costs quickly spiraled out of control. Originally estimated at US$2.4 billion, the project had an excess of $7.5 billion (Dubin, 2017).

Repeated delays and cost overruns eventually forced the suspension of work (Swartz, 2021). While the project was intended to gasify lignite coal and capture the resulting CO2, its original purpose was undermined when the plant shifted to natural gas, leaving much of the carbon capture equipment idle and unused.

Gorgon, Australia

Once hailed as a global showcase for CCS, Chevron’s Gorgon project has struggled to meet expectations. Located at the company’s massive LNG facility on Barrow Island, Gorgon was designed to strip CO2 from natural gas and store it underground. Yet, Chevron reports that it has so far buried just over 10 million tonnes of CO2, barely a third of its original target (Mercer, 2024).

Technical problems, particularly with reservoir pressure, have limited injection rates and delayed progress toward sequestering the promised 80% of the plant’s emissions. Since commencing operations in 2019, performance has steadily declined: CO2 capture dropped from 34% in 2022–23 to just 30% in 2023–24, representing only a small fraction of the facility’s total emissions (Denis-Ryan & Morrison, 2024). To compensate, Chevron has been forced to implement costly technical fixes and purchase carbon offsets.

The difficulties at Gorgon reflect a broader pattern. Wang et al. (2021) observe that most CCUS projects over the past three decades have either struggled or failed to achieve their objectives. Larger plant sizes, in particular, increase the risk of underperformance, and existing support mechanisms have not been sufficient to overcome these challenges. Achieving gigaton-scale deployment will therefore require reducing risk, improving returns, and better aligning technology, policy, investment, and deployment.

Boundary Dam, Canada

Canada’s Boundary Dam 3 (BD3) coal plant in Saskatchewan offers another example. In March 2021, BD3 marked the capture of its four millionth metric ton of CO2, two years later than forecast, underscoring its failure to achieve the 90% capture rate originally promised (Energi Media, 2024). 

The retrofit cost more than CAD 1 billion, yet performance has consistently fallen short. Through 2023, the long-term capture rate averaged only 57%  (IEEFA 2021). The system operates roughly 80% of the time, and when running, it processes just 73% of the plant’s flue gases, leaving a substantial portion of CO2 uncollected.

The plant has rarely achieved its design capacity of 3,200 metric tons per day and has never sustained that level for any extended period. SaskPower has since scaled back its capture target to 65% of emissions. Moreover, a significant portion of the CO2 collected is used for enhanced oil recovery (EOR), which in turn results in additional emissions, thereby reducing the net climate benefit considerably smaller than initially claimed (IEEFA, 2024).

Technical failures have compounded these shortcomings. In 2021, the CCS facility captured 43% less CO2 than the previous year after a breakdown in the main compressor motor forced the system offline for several months (Anchondo, 2022). Although repairs have since been completed, the outage illustrates how dependent carbon capture is on complex, custom-built equipment and how downtime can dramatically reduce emissions removal.

Key findings: The successes show that CCS can be technically feasible, completed on time and within budget, and deliver useful insights into subsurface CO₂ behavior. Yet, the failures highlight recurring challenges: escalating costs, reliance on volatile oil markets, technical underperformance, and uncertain long-term storage integrity. These case studies suggest that CCUS will require stronger policy frameworks, more consistent oversight, and sustained investment to scale effectively. Without these supports, large-scale deployment risks repeating the mixed track record seen so far.

In this series:

• Part 1: Climate Mitigation and the Price of CCUS.

• Part 2: Case Studies

• Part 3: Malaysia’s Big Ambitions

• Part 4: Issues for Successful Deployments

Reach us at khorreports[at]gmail.com

CCUS Role in the Transition to Net-Zero: Part 1

Climate Mitigation and the Price of CCUS

By Claudia Nyon | Edited by Abigael Eminza

This four-part series explores the opportunities, issues, and costs of Carbon Capture, Utilisation and Storage (CCUS), and examines CCUS, with a particular focus on Malaysia’s newly enacted CCUS Act 2025 (Malaymail, 2025).

CCUS has emerged as one of the most debated tools in the global decarbonisation toolkit, straddling the line between necessity and controversy. Initially rooted in the 1920s with natural gas purification and expanded in the 1970s through enhanced oil recovery (EOR), CCUS has since evolved into a proposed solution for hard-to-abate sectors, such as cement and steel. Its relevance has grown in the wake of the Paris Agreement, with more than 30 major projects announced globally since 2020 and countries like Malaysia enacting dedicated legislation such as the CCUS Act 2025 to spur adoption. Yet, despite decades of technical deployment, CCUS costs have remained stubbornly high and resistant to the steep declines seen in renewables, raising questions about scalability and economic efficiency. This introduction sets the stage for examining CCUS’s history, economics, policy drivers, and its contested role in achieving net-zero.

What is CCUS?

Carbon Capture and Storage (CCS) involves capturing carbon dioxide from large point sources, such as power plants, and securely storing it underground to prevent its release into the atmosphere. Carbon Capture, Utilisation, and Storage (CCUS) extends this concept by repurposing captured CO2 for industrial applications. 

Source: Petronas 

History of Carbon Capture and Its Utilisation in Enhanced Oil Recovery

• 1920s: Early carbon capture emerged with natural gas purification, which required separating carbon dioxide from gas streams.

• 1970s: Captured CO2 began being injected into oil fields for Enhanced Oil Recovery (EOR), a practice that continues to this day.

• Today: CCUS remains widely used in EOR to unlock trapped oil reserves, demonstrating one of the earliest and most sustained applications of carbon capture technology.

The practice of capturing carbon dioxide from gas streams traces back to fossil fuel extraction. While oil and natural gas often occur together in the same reservoir, early fossil fuel development largely overlooked natural gas due to the lack of adequate pipeline infrastructure (Energy Information Administration Office of Oil and Gas, 2006). 

By the early 1920s, with improvements in pipeline technology, the demand for natural gas increased, prompting the development of techniques to remove carbon dioxide, known as ‘purification’.

The first commercial CO2 capture and injection for EOR began in Texas in the 1970s (Cherepovitsyn, 2020). EOR remains the largest application of CCUS, as primary/secondary recovery leaves ~⅔ of oil untouched, thereby necessitating the injection of carbon into declining oil fields to unlock trapped reserves (National Energy Technology Laboratory).

Approximately 73% of the carbon successfully captured annually in the United States is utilized for EOR to unlock additional fossil fuel reserves (IEEFA, 2022).

Petronas has implemented EOR techniques to extract fossil fuels in Malaysia (New Straits Times, 2014). 

CCUS and EOR: Statistics of Use

CCUS in Global Climate Change Mitigation

CCUS currently occupies a complex but increasingly central role in carbon policy and carbon economics. 

The Paris Agreement of 2015 set ambitious emissions reduction targets, and the pathway to net-zero emissions by mid-century remains highly debated. This means the world must reduce today’s 50 Gt of total annual CO2-equivalent emissions to around net-zero by mid-century, with reductions of around 40% achieved by 2030 (Energy Transitions Commission, 2022). 

On the back of this, CCUS has positioned itself as a solution to decarbonise industries where alternatives are limited, such as the cement industry that produces 7% of global industrial greenhouse gas emissions (GHGs) (IEA, 2023), and to deliver carbon removals over the next few decades. 

• 30+ commercial CCUS projects announced globally since 2020 (~$27 billion in near-final investments) (IEA, 2020).

• Malaysia’s National Energy Transition Roadmap (NETR) projects CCUS mitigating 5% of energy-sector emissions by 2050 (NETR, 2023). (See Part 2 onwards for more)

Source: International Energy Agency

The Price of CCUS

The Elusive Cost of Carbon Avoidance 

One of the most persistent challenges in evaluating CCUS is the lack of a single, definitive cost estimate for preventing one metric ton of CO2 from entering the atmosphere, a metric known as the "avoidance cost."

The cost of capture ranges from:

• $55/tCO2 for coal-fired power generation (OECD, 2011).

• $64/tCO2 for dilute gas streams such as from cement plants (Jaffar et al., 2023). 

• $71/tCO2 for flue gas (Raksajati et al, 2013).

• $80/tCO2 for open cycle gas-fired power plants (Brandl et al, 2021; Energy Transitions Commission, 2022). 

Early-stage feasibility studies, which often form the basis of projections, tend to underestimate actual expenses by 15% to 30%, according to the OECD (2011), and as also shown in Table 1 at AACE (2005). These estimates can swing even wider when accounting for site-specific variables like infrastructure needs, regulatory hurdles, and regional labor costs. 

For example, a Norwegian study found that adapting CCUS to an existing gas plant required 30% additional spending due to factors like specialized cooling systems and safety upgrades (OECD, 2011). This variability makes it difficult to compare technologies or assume cost advantages for one capture method over another.

The Trade-Off between Capture Rates and Costs

To meet net-zero targets, the CO2 capture rate should be as high as economically viable and as close to 100% as technologically possible. However, modifications in the capture plant design and operations to achieve a 100% capture rate would lead to increased costs. 

To demonstrate, the flue gas from a gas-fired power plant contains approximately 4 mol% CO2. After capturing 99% of the CO2, the resulting CO2 composition is 400 ppm, which is lower than current atmospheric CO2 concentrations. The CO2 separation at the top of the absorber becomes as challenging as direct air capture (Brandl et al, 2021).

For gas-fired power plants, increasing the capture rate from 90% to 96% incurs an additional cost penalty of about 12%, taking the total cost from ~$80 to $90/tCO2. Increasing it to 99% could increase costs to $160/tCO2 (Brandl et al, 2021; Energy Transitions Commission, 2022). 

Most projects, therefore, target a 90 percent capture rate as a pragmatic balance between performance and affordability. Yet even this benchmark is often missed as real-world examples fall short of achieving a high capture rate (>90%) due to cost-minimising decisions, engineering setbacks, or the early-stage nature of technological deployment (to be explored later in this series). 

CCUS costs increase sharply as capture rates approach 100%. Below are the capture rates and costs in a gas-fired power plant

Source: Brandl et al, 2021

Stagnant Costs and Missed Learning Curves 

Unlike renewable energy technologies, which have seen dramatic cost reductions over decades, CCUS has defied expectations of similar progress.

A 2023 analysis noted that cost estimates for fossil power plants with CCUS have remained flat for over 40 years, suggesting a lack of systemic learning across the industry, from carbon capture to burial, despite decades of using all elements of the chain (Bacilieri et al., 2023).

Figure 1, below, shows estimates of the cost of fossil power with CCUS observed in the academic literature and industry reports over the last 40 years. Many of these reports stated that costs were expected to decline in the future due to technological learning. However, the plot makes clear that these expectations have so far not been realised. In fact, quite the opposite – as further information about the technology has been gained, cost estimates have generally risen (Bacilieri et al, 2023).

Source: Bacilieri et al., 2023

This stagnation is striking given that components like CO2 pipelines and injection wells have been used commercially since the 1970s. By contrast, technologies like solar panels and batteries typically reduce costs by 10 percent for every cumulative doubling of production capacity, a pattern CCUS has failed to replicate (Congressional Budget Office, 2023).

The High Price of Over-Reliance on CCUS

The high costs of CCUS have spurred debate about its optimal role in decarbonization. Recent modeling indicates that net-zero pathways relying heavily on CCUS could require $30 trillion more in spending than those prioritizing renewables and energy efficiency (Bacilieri et al., 2023). 

This divergence arises because large-scale CCUS deployment delays the cost declines typically seen in alternatives like wind, solar, and green hydrogen. However, abandoning CCUS entirely isn’t economically viable either: certain industries, such as cement and steel, lack ready substitutes for fossil fuels, making limited CCUS deployment a cost-effective compromise (IPCC, 2023).

Net CO2 emissions over time for our low- (blue dashed lines), medium- (yellow dash-dotted lines), and high-CCUS (red dotted lines) scenarios, and all the other C1 and C2 scenarios (grey solid lines). The black dotted line marks the year 2060, which is the latest year we require selected scenarios to reach net zero. The green band and the vertical black solid and dashed line highlight the corridor of ±10% of today’s CO2 emissions, which we require our scenarios to fall into in 2050. 

Source: Bacilieri et al., 2023

Foreseeable Economic and Policy Challenges

The divergence between high and low CCUS decarbonization pathways reveals a fundamental tension: economies prioritizing rapid scaling of renewables, electrolyzers, and energy storage achieve faster cost reductions through technological learning and economies of scale (Greig & Uden, 2021). 

This dynamic creates a self-reinforcing cycle; accelerated deployment of alternatives further lowers their costs, reducing reliance on CCUS. By contrast, high-CCUS pathways face compounding expenses, as delayed investment in renewables perpetuates dependence on a technology with stubbornly stagnant costs.

Yet dismissing CCUS entirely ignores structural realities. Even critics acknowledge its inevitability for hard-to-abate sectors like cement (see Hughes, 2017), though its role remains hotly contested. Some fear that the technology now confronts a critical juncture, the so-called "valley of death" where technical viability clashes with insufficient private investment (Reiner, 2016). Market forces alone appear inadequate: CCUS ranks among the costliest near-term mitigation options (IPCC, 2022), with most projects requiring government backing to pencil out financially (Rempel et al., 2023). This dependency is exacerbated by the fossil fuel industry’s tepid commitment; oil and gas firms allocated less than 1% of 2020 capital expenditures to clean energy (World Energy Investment, 2021), raising questions about their willingness to drive meaningful CCUS scale-up without policy mandates.

Key findings: CCUS is neither a silver bullet nor universally accepted, but it’s unavoidable for net-zero, particularly in hard-to-abate industries. The debate now centers on how much CCUS is optimal, balancing cost, scalability, and emissions goals.

In this series:

• Part 1: Climate Mitigation and the Price of CCUS

• Part 2: Case Studies

• Part 3: Malaysia’s Big Ambitions

• Part 4: Issues for Successful Deployments

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