This analysis identifies and discusses the three greatest contributions that carbon capture, utilisation and storage can make to power system transformation:

• Tackling emissions from existing plants. In the near and medium term, retrofitting the power sector with carbon capture technologies addresses emissions from the existing fossil-fuelled fleet of power plants. These retrofits enable owners of existing power plants to recover their investment and, in doing so, to reduce the cost of power system transformation. CCUS retrofits are particularly important in Asia, with its young fleet of fossil‑based power plants.
• Flexibility for stable power. Carbon capture technologies further help power networks achieve electricity security goals. Many regions have growing shares of power from variable renewables, driving a greater need for flexibility to ensure the stable operation of their power systems. CCUS-equipped power plants can provide this extra flexibility across broad timescales, ranging from the very short term (e.g. grid services, inertia and frequency ancillary services) to the very long term (e.g. seasonal variations).1
• In addition, carbon capture provides a technological hedge as the power system undergoes transition. Networks face uncertainty in operating with very high shares of renewables (Phases 5 and 6 of renewables integration according to IEA classification), and they will need technological innovations. This concerns, in particular, the balancing of longer-term seasonal variations, and to a lesser extent very short‑term flexibility provision (e.g. inertia, frequency control, dispatchability). Our expectations for these innovations are positive (e.g. for advances in battery technology or synthetic inertia), in particular for short-term flexibility, but the full portfolio of technologies will need to be developed and deployed to support a rapid transformation.
• Net-zero and negative emissions. The long-term value of carbon capture technologies to the power system (and the energy system as a whole) may further increase in line with more ambitious climate goals due to its ability to enable negative emissions from power generation when combined with bioenergy. Negative emissions can counterbalance residual emissions in other sectors that are harder-to-abate (i.e. they are costlier or have limited technology solutions), thereby reducing the cost of energy sector decarbonisation.

These are discussed in turn after we have established the rationale for including carbon capture technologies in power systems that are undergoing a low-carbon transformation.

Carbon capture has consistently been identified as an integral part of a least-cost portfolio of technologies needed to support the transformation of power systems globally.2 These technologies play an important role in supporting energy security and climate objectives by enlarging the portfolio of low-carbon supply sources. This is of particular value in countries where fossil-based power generation is likely to retain an important role, for example due to existing infrastructure or abundant domestic resources. Similarly, other options may be constrained, for example, where renewable energy potential is limited due to poor solar radiation or wind potential, or limited land availability. Wind and solar power plants occupy much larger amounts of land than CCUS-equipped power stations, which can give rise to constraints on siting.

Including carbon capture in the portfolio of technology options can reduce the total cost of power system transformation. Previous analysis by the IEA highlighted that if the availability of CO₂ storage was limited across the global energy system, the marginal abatement costs in the power sector would increase from around USD 250/tCO₂ in 2060 in a low carbon pathway to USD 450/tCO₂. A 2019 report that targeted regional studies found that the cost of decarbonising the UK power system would be about 50% higher if carbon capture was not available. In Poland it would be 2.5 times higher, and in New South Wales in Australia it would be twice as high.

Future power systems will be more distributed and diverse. In this new paradigm, future power generation assets will be valued not only for energy, but also for a diverse set of services like grid services, inertia and frequency provision, or turn down capabilities and dispatchability. All of these services are essential for a reliable and affordable power supply. This is a key reason why traditional cost metrics like the levelised cost of electricity (LCOE) are often inadequate, as they do not reflect the total cost and value of generation assets to the operation of the power system.

While electricity demand is increasing, the global power sector has to dramatically reduce its carbon intensity to play its part in achieving the critical energy-related Sustainable Development Goals and the Paris Agreement target.

The IEA Sustainable Development Scenario outlines a major transformation of the global energy system to achieve them. Under this Scenario, carbon capture technologies play an important role in providing dispatchable, low-carbon electricity. By 2040, 315 GW of electricity generation capacity is equipped with carbon capture, utilisation and storage. This is the equivalent of adding retrofit and new-build CCUS capacity of around 15 GW per year on average over the next two decades.3 Annual spending on fossil-fuelled plants equipped with carbon capture technologies rises to almost USD 30 billion per year, with most of this increase coming in the second half of the outlook period.

In 2040, CCUS-equipped plants generate 1 900 TWh, or 5% of global power, up from some 470 TWh or 1.5% in 2030. 

Coal-fired generation falls dramatically in the Sustainable Development Scenario. The combination of CO₂ and air pollution policies in this Scenario contributes to a steep reduction in the share of coal-fired power generation, from around 38% today to around 6% in 2040.

Of the remaining coal-fired power generation, 40% comes from plants fitted with carbon capture technologies. In 2040 the 160 GW of coal-fired capacity with these technologies generates 1 000 TWh, or 2.6% of global power generation at an emissions intensity of some 90-100 gCO₂/kWh. This is based on CO₂ capture rates of 90% – recent analysis has highlighted the possibility of higher capture rates at only a small increase in capture costs. Coal plants without these technologies run at very low capacity factors, well below 20% for all but the most efficient plants, and generate about 1 400 TWh in 2040.

Natural gas-fired power generation increases globally until the mid-2020s, peaking at some 24% of the power mix, before falling to 14% by 2040. Natural gas plants equipped with carbon capture capabilities produce around 900 TWh of electricity in 2040, around 16% of total gas-fired power generation, with an emissions intensity of less than 40 gCO₂/kWh. In total, the use of carbon capture for gas in power generation avoids over 300 MtCO₂ in 2040.

Some 9.7 GtCO₂ are captured cumulatively from power generation to 2040 in the Sustainable Development Scenario, an amount equivalent to more than a decade of emissions from the global aviation industry (based on 2019 emissions). While the share of generation from plants equipped with carbon capture is split almost equally 50:50 coal-fired and gas-fired, the vast majority of the CO₂ captured in the power sector is from coal-fired power plants due to their higher carbon intensity. Coal-fired power plants account for 7.0 GtCO₂ or more than 70% of total CO₂ captured in the sector through to 2040. In addition to CO₂ captured from coal and gas, the Scenario also identifies some 400 MtCO₂ captured from bioenergy for power in the period to 2040.

CCUS retrofits provide a solution to emissions from existing (and planned) fossil-fuelled power generation, recognising that much of the global fossil fuel power fleet is unlikely to be shut down within a timeframe that meets climate targets. The global fleet of fossil-fuelled power plants is surprisingly young. For example, almost one-third of all coal-fired power capacity is less than ten years old, the vast majority of which is in Asia. 

In light of the young age of the fossil-fuelled power fleet and increasingly strict emission regulations in several countries, CCUS retrofits provide plant owners with an important asset protection strategy that allows them to continue operations at existing plants while meeting carbon reduction targets and thereby recover some of the remaining capital at risk. Owners and investors have yet to recover more than USD 1 trillion of capital expenditure in the existing coal fleet alone, most of it in Asia.

A large share of these assets is state-owned (e.g. in China), and governments will take into consideration a multitude of factors when deciding on the future of existing infrastructure, including electricity price impacts, implications for employment and the financial health of state-owned enterprises.

Carbon capture retrofits are most attractive for young and efficient power plants that are located near places with opportunities to use or store CO₂, including for enhanced oil recovery, and where alternative generation options are limited.

Certain technical features of existing power plants have to be considered when assessing whether a retrofit is likely to make commercial sense in conjunction with the policy environment. These factors include age, capacity, availability of on-site space for carbon capture equipment, load factor and type, and location of fuel source. Attributes such as cooling type and the steam cycle design of coal plants will have a critical impact on the cost of retrofitting.

Further, carbon capture retrofits require high confidence in the availability of CO₂ storage or demand for use. IEA analysis of the existing coal power plant fleet in China concluded that over 300 GW could be suitable for retrofit when taking into account these considerations.

Addressing the emissions of existing coal-fired power plants or those being built today will be critical to reach climate goals. The IEA has outlined options to address the emissions of the existing coal-fired power plant fleet featuring three pillars: a) the retrofit of plants with carbon capture technologies, b) the repurposing of coal plants to provide flexibility, and c) the gradual phase-out of plants where carbon capture is not possible. 

In the Sustainable Development Scenario, 120 GW of existing coal-fired capacity is retrofitted with carbon capture by 2040, accounting for some 80% of the coal plants equipped with these technologies. More than 110 GW of these retrofits are in China, representing a capital investment of around USD 160 billion. A further 10 GW are in the United States. Without carbon capture available at scale in power, coal-fired power generation, and eventually also gas-fired generation, would need to be virtually eliminated to meet long-term climate goals, with significant early retirements and potential stranding of assets. 

Over 750 GW of existing coal plants reduce operations to cut emissions in this Scenario, limiting electricity production but still providing system adequacy and flexibility. About one-quarter of the existing fleet would be retired before reaching the typical 50-year lifespan. Shutdowns and reduced operating hours are likely to lead to balance sheet write-downs for some owners of existing facilities. Coal plant retirements also imply greater investment in other low-carbon sources of electricity and associated network infrastructure.

Carbon capture retrofits also play an important role for the gas-fired power plant fleet, which currently has an average age of only around 19 years. In the SDS 155 GW of natural gas-fired power plants are equipped with carbon capture, utilisation and storage by 2040, almost half of them in the United States. Of the CCUS-equipped capacity, about 55% relates to new plants and 45% to retrofitted, providing a total of around 900 TWh in 2040.

Flexibility and electricity security are increasingly important issues for power systems, particularly those that are integrating a growing share of variable renewable energy in daily operations. Flexibility in this context relates to the ability to respond in a timely manner to changes in electricity supply and demand in numerous timescales, from the very short term (subseconds, seconds, minutes and hours) to the balancing of weekly, monthly or seasonal demand and supply variations. For system operators, the priority timescales depend on the share of renewables in a power system, with longer-term flexibility concerns typically growing in importance as renewables expand.

Flexibility can generally be provided through four main levers: demand response, grid interconnections, dispatchable power generation and energy storage. To date, conventional thermal and hydro power plants have acted as the primary source of system flexibility, maintaining the reliability of power systems around the world and helping to accommodate rising shares of variable renewable energy.

In part, thermal power plants have made this possible by retrofitting various technologies, ranging from advanced monitoring and control technologies to deeper technical interventions.4 These have helped to improve the plants’ flexibility performance (e.g. increased ramp rates, lower minimum stable loads of generation, shorter start-up times and shorter minimum up and down times). The construction of more flexible power plants, such as open-cycle gas turbines, also helps.

The very high share of renewables generation and capacity by 2040 in the Sustainable Development Scenario requires an extremely flexible power system to ensure stable and secure operation. The Scenario sees a significant increase in the need for flexibility along all timescales. When expressed, for instance, as peak ramping requirements, flexibility needs grow even faster than electricity demand. Developing economies experience notable acceleration in the need for flexibility – it is in these countries where almost 90% of growth in global electricity demand takes place in the Scenario, and where renewables meet a significant amount of new demand. In 2040 India’s power system needs six times more flexibility than today, and China’s requires three times more. But advanced economies also need higher levels of flexibility; for example, in the United States they are 2.5 times today’s level in 2040.

To address this rising need for flexibility, system operators will need new flexibility sources. Batteries, demand response and sector coupling are poised to play pivotal roles in making sure future power systems are secure and reliable, in particular for short-term flexibility.

Demand-side response has a role to play in meeting rising flexibility needs, for example by shaving peak demand and redistributing electricity to time periods when the load is smaller and electricity is cheaper. Distributed resources, including variable renewables themselves, storage and demand response can also become key flexibility sources when allied with appropriately designed markets, as is happening in several countries. 

Thermal plants equipped with carbon capture, utilisation and storage techologies are also expected to play an important role in providing flexibility. Plant operators can run them in a flexible manner to accommodate short-term variations, very much like unabated thermal power plants today. These technologies have various effects on plant operation. Indeed, carbon capture capabilities may even in some instances increase short-term flexibility as the operator can increase or reduce the energy used by the CO₂ capture unit to follow electricity load fluctuations. The International CCS Knowledge Centre’s Shand feasibility study also identified that the CO₂ capture rate could increase from 90% at full load to 97% at the minimum power plant output level (to make way for renewable sources) at almost no additional cost.

While short-term flexibility is well understood today and technological innovations (e.g. batteries) may ultimately be able to meet these requirements without support from thermal generators,5 seasonal or long-term fluctuations in electricity supply arguably present a more significant challenge. They underscore the value of dispatchable forms of generation, including CCUS-equipped plants. Many regions experience pronounced seasonality of renewables generation, presenting power system operators with significant fluctuations across the year; for example, in Germany, part of the temperate climate zone, solar power generation in January 2019 was only around 10% of summer generation in the peak month of June.

To date, thermal generators have played an important role in balancing this kind of seasonality, as well as meeting unexpected shortfalls in renewable generation over extended periods of time (e.g. several days to weeks). The graphic representation of the German electricity system in January 2019 demonstrates this. Wind and solar generation was very limited at a time of high winter heating demand and coal generators ramped up over an extended period to cover for the generation shortfall.

Cost-effective alternatives to manage these seasonal variations are currently limited and there is no “one size fits all” solution. Improved regional integration or interconnectors could play an important role in some regions – and indeed are a feature of many systems with a high penetration of variable renewables today. But they require co‑ordination across jurisdictions and may be limited by national energy security considerations and/or the presence of similar weather patterns across regions.

Nuclear power could fill the shortfall in renewables generation at comparable economics to carbon capture, but a reduction in nuclear capacity is expected in many advanced economies, such as Belgium, Germany, Korea, Spain and Switzerland, due to economic and political headwinds.

Given today’s technology characteristics, battery solutions are generally better suited to cost-effectively balance shorter-term supply–demand imbalances (up to several hours), but face challenging economics to bridge longer-term imbalances.

Hydro storage as a backup for an entire power system for an extended period of time is, for most countries, impractical due to limited hydro expansion potential. This highlights the value of having a full portfolio of technology solutions available to support energy security and emissions reductions objectives.

An alternative flexibility route is the generation of low-carbon hydrogen or ammonia (e.g. through electrolysis or steam methane reforming with carbon capture) and their use in, for instance, combined-cycle gas turbines. 

When comparing renewables and thermal generators, a one-to-one replacement of renewables with thermal generators on a pure capacity or generation basis is typically not feasible. CCUS-equipped plants offer higher load factors than variable renewable energy sources. On average, thermal carbon capture capacity of 1 GW would require some 2-5 GW of wind or solar capacity to achieve similar power generation levels.

This 2-5 GW, however, does not translate into a similar level of security of supply due to their intermittent nature. Power system planners therefore typically do not consider the entire rated capacity of variable renewables to be guaranteed available should it be needed. The fraction that is considered guaranteed and, hence, the value to the system of any additional unit of variable renewable capacity may further decrease with the amount of variable renewable capacity already in the system, a feature that has been exhibited in capacity auction markets like the PJM market in the United States.

The competitiveness of carbon capture in the power system relative to other generation sources increases when the full value of this power as a flexible, secure and low-carbon source of electricity is taken into account.

The levelised cost of electricity is the most common metric for comparing the competitiveness of power generation technologies, but considers only the costs of generation. It does not take into account the value that each technology may provide to the overall electricity system in ensuring flexibility and reliability. This, however, is becoming increasingly important given the unprecedented changes power systems are undergoing, including rising shares of variable renewables and an increasing need to source power system flexibility. A more complete picture of competitiveness requires system planners to consider these values. The value-adjusted LCOE, a new metric presented in World Energy Outlook 2018, combines a technology’s costs with estimates of these values.

Using the value‑adjusted LCOE measure, plants equipped with carbon capture (retrofits, in particular) perform more competitively than when simply using the LCOE. This is mainly due to the increasing system value associated with enhancing system reliability and flexibility services as the share of variable renewables in total generation increases.

IEA analysis shows that the value‑adjusted LCOE for thermal power plants is up to 15% lower than the corresponding LCOE measure, depending on the characteristics of the power system and given moderate renewables penetration of some 20‑30% in the system. Likewise, the value‑adjusted LCOE of renewables can increase by up to 5% compared to the LCOE measure, thereby making thermal operators (with carbon capture) more competitive if we adequately account for the flexibility and capacity value of plants. In systems with higher shares of renewables, these effects are likely to be more pronounced as the value of flexibility and secure capacity increases.

When combined with bioenergy, carbon capture and storage can support net-zero or even negative emission power plants. Bioenergy with carbon capture and storage  plays a uniquely important role in meeting ambitious climate goals due to the potential for negative emissions.6 Negative emissions from bioenergy with carbon capture arise due to the fact that biomass absorbs CO₂ as it grows, and, when combusted for energy, the CO₂ is released back into the atmosphere, creating a full cycle with a neutral impact on atmospheric volumes of CO₂. When combined with the CO₂ capture and storage process, much or all of the CO₂ absorbed by the biomass may be permanently removed from the atmosphere.

These negative emissions can play an important role in offsetting emissions from other sectors where direct abatement is either technologically difficult or prohibitively expensive, including long-distance transport and some industrial processes. Within the power sector, generators that utilise bioenergy with carbon capture have the potential to offset emissions from the use of (for example) gas-fired peaking power plants, which play a key role in supporting the cost-effective integration of renewables but are incompatible with a net-zero power system.

Dedicated plants using bioenergy with carbon capture technologies typically feature higher investment costs, lower efficiencies and higher cost of fuel (biomass) compared with coal- or gas-fired plants with carbon capture. With stronger climate ambition and higher carbon prices, bioenergy with carbon capture and storage becomes increasingly competitive when monetisation of negative emissions is permitted in a carbon trading system. The LCOE analysis in the graph is used for illustrative purpose only, but the more complex calculations underlying a value‑adjusted LCOE computation would show similar effects.

Biomass co-firing in combination with carbon capture at very high rates (e.g. exceeding 99%) may be one of the most cost-effective ways to decarbonise existing fossil power infrastructure. Co-firing can lower the costs of bioenergy in power by taking advantage of the economies of scale associated with fossil‑based power plants. Analysis by IEA Greenhouse Gas R&D Programme highlights that the most economical option to achieve carbon-neutral ultra-supercritical coal plants may be the co-combustion of 10% biomass at a 90% CO₂ capture rate. This would increase the CO₂ avoided cost by only 1.5% relative to a CCUS-equipped coal plant without biomass co-firing, to around 62 USD/tCO₂. Further increasing the share of bioenergy or higher capture rate may result in negative emission power plants.

The unique ability to achieve negative emissions through carbon capture technologies may also open up the possibility of allowing these plants to run at high capacity factors even in a power system with high renewable shares. This would potentially come at the expense of a reduced contribution to system flexibility, but would improve the economics of CO₂ transport and storage infrastructure through higher utilisation factors and economies of scale. 

In some countries, thermal power plants operate at comparably low capacity factors today to help integrate growing shares of low-marginal-cost renewables. The business model for CCUS-equipped plants to operate flexibly will rely crucially on decision makers designing the electricity market so that it adequately remunerates flexibility services. Currently, CCUS plants are capital intensive and it is questionable whether owners of newly built or retrofitted plants would be able to recover their costs if required to operate at very low capacity factors. Similarly, the associated CO₂ transport and storage infrastructure would, in the absence of other users, face lower utilisation rates and challenging economics.

However, in an energy system with strong climate ambition, the ability of bioenergy with carbon capture and storage to provide negative emissions to help offset emissions from other sectors may prove more valuable than its capability for flexibility provision. In this case there might be better options for flexibility, for example gas peaking plants.