Natural gas power plants have become a cornerstone of the global energy system, prized for their operational flexibility, high efficiency, and lower carbon intensity compared to coal-fired generation. They provide reliable baseload power and can ramp up quickly to balance intermittent renewables like wind and solar. However, natural gas combustion still releases substantial volumes of carbon dioxide (CO2) into the atmosphere — roughly 40–50% less than coal per unit of electricity, but still a significant contributor to climate change. As nations tighten emissions targets under the Paris Agreement and pursue net-zero goals, the electric power sector faces mounting pressure to decarbonize. Carbon capture, utilization, and storage (CCUS) technologies offer a pragmatic pathway to mitigate the climate impact of existing and new natural gas plants while preserving grid reliability and energy security.

Carbon capture technologies are not a single solution but a suite of engineering approaches designed to separate CO2 from flue gas or fuel gas streams before it escapes to the atmosphere. When applied to natural gas power plants, these systems can capture 90% or more of the CO2 generated, significantly reducing the facility's overall carbon footprint. The captured CO2 is then compressed, transported via pipeline or ship, and injected deep underground into geological formations such as depleted oil and gas reservoirs, saline aquifers, or basalt formations for permanent storage. In some cases, the CO2 can be utilized in enhanced oil recovery (EOR) or converted into synthetic fuels, chemicals, and building materials, though storage remains the dominant long-term solution. The integration of carbon capture with natural gas power plants is increasingly seen as a critical bridge technology, enabling continued use of fossil fuel infrastructure during the transition to a fully renewable energy system.

The Basics of Carbon Capture Technologies

All carbon capture systems share three fundamental stages: capture, transport, and storage. The capture stage is the most technically diverse and energy-intensive. During capture, CO2 is separated from other gases — either before or after combustion, or by modifying the combustion process itself. The captured CO2 is then purified, compressed to a dense phase (typically above 73 bar), and transported via pipeline or ship to a storage site. At the storage site, the CO2 is injected into porous rock formations at depths of 1–3 kilometers, where it is trapped by a combination of structural, capillary, and geochemical mechanisms. Monitoring programs using seismic surveys, pressure gauges, and groundwater sampling ensure the CO2 remains contained for centuries to millennia.

Natural gas plants present both advantages and challenges for carbon capture. The CO2 concentration in natural gas flue gas is relatively low — typically 3–5% by volume for a combined cycle gas turbine (CCGT), compared to 12–15% for coal plants. This lower concentration makes separation more difficult and requires larger volumes of solvent or sorbent to achieve high capture rates. Conversely, natural gas plants produce much less flue gas per unit of electricity than coal plants, which can reduce the physical footprint of the capture equipment. Advances in solvent chemistry, process integration, and heat recovery are steadily improving the economics and efficiency of capture on gas turbines.

Types of Carbon Capture for Natural Gas Plants

Post-Combustion Capture

Post-combustion capture is the most mature and widely deployed carbon capture technology, applicable both to new builds and retrofits of existing natural gas plants. In this approach, the flue gas from the gas turbine exhaust is cooled and passed through an absorber column where it contacts a liquid solvent — typically an amine solution such as monoethanolamine (MEA) or advanced blended amines. The solvent chemically binds with the CO2, capturing it while allowing other flue gas components (nitrogen, oxygen, water vapor) to release to the atmosphere. The CO2-rich solvent is then heated in a regenerator column to release a nearly pure stream of CO2, which is dehydrated, compressed, and sent to storage. The regenerated solvent is recirculated back to the absorber. Post-combustion systems can achieve 90–95% capture rates, and ongoing research aims to push that to 99%.

A notable industrial example is the Quest CCS facility in Alberta, Canada, which captures CO2 from hydrogen production units at an oil sands upgrader (though not a power plant). Similarly, the Petra Nova project in Texas demonstrated post-combustion capture on a coal power unit. For natural gas specifically, the Net Zero Teesside project in the UK plans to capture CO2 from a cluster of gas-fired power plants and industrial sources, transporting it via pipeline for offshore storage under the North Sea. These projects validate the core process and provide important cost and performance data for future gas plant retrofits.

Pre-Combustion Capture

Pre-combustion capture takes a fundamentally different approach: it removes carbon from the fuel before combustion. For natural gas, this involves reforming the methane (CH4) with steam to produce syngas (a mixture of hydrogen and carbon monoxide), followed by a water-gas shift reaction that converts the carbon monoxide to carbon dioxide and additional hydrogen. The resulting stream contains roughly 15–20% CO2 at high pressure, which can be separated using physical solvents (e.g., Selexol, Rectisol) or membrane systems, ultimately yielding a hydrogen-rich fuel. The hydrogen is then combusted in a gas turbine designed to burn hydrogen, producing only water vapor and nitrogen oxides (which are controlled by selective catalytic reduction). The captured CO2 is at a much higher partial pressure than in post-combustion cases, reducing the energy penalty for separation.

Pre-combustion capture is particularly suited to integrated gasification combined cycle (IGCC) plants, but for natural gas it aligns with the growing interest in blue hydrogen production. Facilities that produce hydrogen from natural gas with CCS can supply both industrial hydrogen and low-carbon fuel for power generation. A prominent example is the Air Products hydrogen production plant in Port Arthur, Texas, which captures CO2 for EOR. However, commercial-scale pre-combustion capture for power generation remains limited, partly because hydrogen turbines are still in the early stages of deployment. Major gas turbine manufacturers are developing combustion systems capable of firing high-hydrogen fuels, with early projects expected online in the late 2020s.

Oxy-Fuel Combustion

Oxy-fuel combustion eliminates the nitrogen ballast from air by burning natural gas in nearly pure oxygen (typically >95% purity). The resulting flue gas consists mainly of CO2 and water vapor, with minor amounts of oxygen, nitrogen, and argon. After cooling and condensing the water, a relatively pure CO2 stream remains, ready for compression and transport without the need for a chemical solvent. The oxygen is produced via an air separation unit (ASU), which consumes a significant amount of electricity and imposes an energy penalty of 8–12 percentage points on the plant's net efficiency.

A variant known as the Allam-Fetvedt Cycle uses supercritical CO2 as the working fluid in a closed-loop, oxy-fuel combustion turbine. This cycle achieves high thermodynamic efficiencies (over 55% net LHV) while inherently capturing nearly all CO2 and other pollutants. A demonstration plant in La Porte, Texas, has been operating since 2018, and a full-scale commercial 300 MW plant is under development at the Pecos, Texas site. Oxy-fuel combustion offers the advantage of near-zero emissions, but the capital cost of the ASU and the need for specialized turbines remain hurdles. If costs decline and reliability is proven, oxy-fuel cycles could become a leading option for new natural gas power plants with carbon capture.

Benefits Beyond Emission Reduction

The primary benefit of integrating carbon capture into natural gas power plants is the deep reduction in greenhouse gas emissions — typically 90% or more of the CO2 generated. This positions natural gas as a low-carbon firm power source that can complement high penetrations of renewables. Unlike wind and solar, gas plants with CCS can operate whenever needed, providing grid reliability and dispatchability without the carbon burden. This dual role is critical for regions phasing out coal and nuclear while expanding solar and wind capacity.

Carbon capture also helps natural gas plants comply with increasingly stringent emissions regulations, carbon pricing mechanisms, and emissions performance standards. For example, the US Environmental Protection Agency's proposed rules under Section 111(d) of the Clean Air Act require existing coal and new gas plants to install carbon capture or achieve equivalent emission reductions. In Canada, the proposed Clean Electricity Regulations set a carbon intensity limit that effectively mandates CCS on any new unabated gas generation. Early adoption of capture technology can provide a compliance advantage and avoid future retrofit costs or plant retirements.

Furthermore, carbon capture supports the broader energy transition by enabling the production of blue hydrogen from natural gas. Hydrogen is increasingly seen as a versatile energy carrier for decarbonizing industry, heavy transport, and seasonal energy storage. When natural gas is reformed with CCS, the resulting hydrogen is considered low-carbon and can be sold into growing hydrogen markets. Several large-scale blue hydrogen projects — including H2H Saltend in the UK and the HyNet North West cluster — are anchored by gas reforming with CCS. These projects create jobs, stimulate investment in pipeline and storage infrastructure, and provide a stepping stone toward green hydrogen produced by electrolysis using renewable electricity.

Economic Challenges and Incentives

Despite the clear environmental benefits, carbon capture on natural gas plants faces substantial economic barriers. The cost of capturing CO2 from natural gas combined cycle plants is estimated at $40–$80 per tonne of CO2 avoided, depending on capture rate, plant size, fuel cost, and site-specific factors. The energy penalty — the loss of net electricity output due to steam extraction and auxiliary power consumption — ranges from 8% to 12% for post-combustion capture. This means a plant must burn more fuel to deliver the same net power, offsetting some of the emission reduction. Capital costs for a capture system can add 50–100% to the capital cost of the power plant itself.

To bridge this cost gap, governments have implemented a variety of financial incentives. In the United States, the Section 45Q tax credit provides up to $85 per tonne of CO2 stored in geological formations (increased from $50 by the Inflation Reduction Act of 2022). This credit is transferable and can be claimed for 12 years after the capture system begins operation. The credit level is sufficient to make many natural gas CCS projects economically viable, especially when combined with other revenue streams such as EOR or hydrogen production tax credits. The US Department of Energy also provides funding for CCS demonstration projects through the Office of Fossil Energy and Carbon Management.

In Europe, the Innovation Fund supported by the EU Emissions Trading System (ETS) grants billions of euros to large-scale CCS and hydrogen projects. The UK's Cluster Sequencing Program is providing capital support and a regulated revenue model for the first CCS clusters, including industrial and power applications. Canada's federal carbon tax, combined with provincial clean fuel standards and investment tax credits for CCS (announced in 2022), creates a strong investment signal. To learn more about current policy frameworks, visit the Global CCS Institute's resources and the DOE Carbon Capture program page.

Current Deployment and Notable Projects

While carbon capture on coal plants has received more attention historically, natural gas CCS projects are now gaining momentum. As of 2025, there are over 20 commercial-scale CCS projects operating or under construction that involve natural gas processing, hydrogen production, or gas-fired power. Among the most significant:

  • Northern Lights Project (Norway): An open-access CO2 transport and storage network operated by Equinor, Shell, and TotalEnergies. It will receive captured CO2 from industrial sources including the Brevik cement plant and the Fortum Oslo Varme waste-to-energy plant, but is designed to serve multiple emitters, including gas power plants. First storage injection began in 2024. (Northern Lights website)
  • Gorgon Carbon Dioxide Injection Project (Australia): One of the world's largest CCS projects, capturing CO2 from a liquefied natural gas (LNG) facility. It stores up to 4 million tonnes per year in a deep saline formation. Though not a power plant, it demonstrates the scalability of CO2 storage from gas processing.
  • Net Zero Teesside (UK): A cluster of power and industrial sources in the Teesside region, including a new gas-fired power plant with CCS. The project aims to capture up to 6 million tonnes of CO2 per year, transported via a shared pipeline to the North Sea. Final investment decision expected in 2024, with operations by 2028.
  • Enchant Energy San Juan Generating Station (USA, proposed): Originally a coal plant, the project plans to retrofit with CCS, but the technology and site infrastructure lessons apply to gas plants as well.
  • Pecos Allam-Fetvedt Plant (USA): A 300 MW oxy-fuel natural gas power plant under development by 8 Rivers Capital. If built, it would be the first commercial-scale gas power plant with near-total CO2 capture.

These projects signal a growing pipeline of gas-related CCS projects, driven by policy support and corporate net-zero commitments. The Global Status of CCS 2024 report provides an annual update on project developments with detailed capacity and cost data.

Integration with the Energy System

Natural gas power plants with carbon capture are uniquely positioned to serve as a low-carbon backbone for grids with high renewable penetration. Unlike unabated gas plants, which would exceed carbon budgets in a net-zero world, CCS-equipped plants can run for many hours each year without prohibitive emissions. They can operate in load-following mode, ramping up when solar and wind generation dips, and cycling down when renewable output is abundant. This flexibility is essential for maintaining grid stability as coal plants retire and nuclear capacity declines in some regions.

Moreover, natural gas with CCS enables the production of blue hydrogen at scale, which can be used for power generation in hydrogen turbines or fuel cells. In this scenario, the gas plant acts as a flexible, low-carbon electricity source, while the hydrogen produced elsewhere can be stored in salt caverns or depleted gas fields for seasonal balancing. Countries like the UK, Germany, Japan, and South Korea are actively exploring hydrogen-ready gas turbines as part of their national hydrogen strategies. For example, the H21 North of England project envisions converting the gas grid to 100% hydrogen, with new hydrogen storage and power generation infrastructure anchored by natural gas reforming with CCS.

Another integration pathway is to co-fire natural gas with biomass in a power plant and capture the resulting CO2, achieving bioenergy with carbon capture and storage (BECCS). This combination results in negative emissions because the biomass absorbs CO2 during growth, and the capture process prevents its re-release. BECCS is considered essential in many integrated assessment models for limiting global warming to 1.5°C or 2°C. The Drax power station in the UK, which converted from coal to biomass, is piloting BECCS technology with a target of capturing several million tonnes of CO2 per year by 2030. Applying BECCS to natural gas plants would require a dedicated biomass supply chain, but could offer a near-term path to negative emissions alongside unabated renewables.

Future Outlook and Innovation

The trajectory of carbon capture on natural gas power plants will depend on continued cost reductions, supportive regulatory frameworks, and the development of next-generation capture technologies. Key innovation areas include:

  • Advanced solvents and sorbents: New amine blends, water-lean solvents, and solid sorbents (including metal-organic frameworks and amine-functionalized silica) promise lower energy penalties, higher stability, and reduced degradation. Some systems aim to capture CO2 at temperatures above 100°C, enabling heat integration at higher efficiencies.
  • Membrane separation: Polymer and ceramic membranes that selectively separate CO2 from flue gas could simplify capture processes, reduce capital costs, and allow modular, scalable deployment. Recent advances in thin-film composite membranes show promise for natural gas flue gas conditions.
  • Direct air capture (DAC): While not directly applied to power plants, DAC can be co-located with natural gas plants to capture CO2 from ambient air, using waste heat from the power block. Companies like Climeworks and Carbon Engineering are scaling DAC, and integration with gas plants could provide a pathway to net-negative emissions.
  • Cryogenic carbon capture: Processes that cool flue gas to extremely low temperatures, freezing out CO2 as a solid, are under development. These systems avoid chemical solvents and can capture multiple pollutants simultaneously, but require careful heat integration to minimize the energy penalty.
  • Electrochemical capture: Using electricity to drive pH-swing cycles for CO2 separation, potentially offering lower temperature regeneration and the ability to produce value-added products like carbonates or synthetic fuels.

On the policy front, the expansion of carbon pricing, the emergence of low-carbon fuel standards, and the inclusion of CCS in clean electricity mandates will accelerate deployment. The US Inflation Reduction Act's 45Q credit, combined with the new Clean Hydrogen Production Tax Credit (45V), creates a powerful financial incentive for building gas plants with CCS and blue hydrogen facilities. The EU's proposed net-zero industry act aims to boost domestic CCS capacity to 50 million tonnes per year by 2030.

Looking further ahead, the role of natural gas in a fully decarbonized energy system is uncertain. By mid-century, renewables plus storage and expanding grid interconnections may be able to meet all electricity demand without fossil fuels. However, for the next two decades, natural gas will remain a critical part of the generation mix in many regions. Carbon capture technologies offer the only credible pathway to operate these plants in alignment with climate goals. Continued investment in R&D, demonstration projects, and CO2 transport and storage infrastructure is essential to bring down costs, prove reliability, and build public trust.

The impact of carbon capture on natural gas power plants extends far beyond the plant fence line. It enables a managed transition for communities dependent on fossil fuel economies, preserves existing energy infrastructure and grid assets, and provides a flexible, dispatchable source of low-carbon electricity that can accelerate the growth of variable renewables. As countries update their nationally determined contributions and develop long-term low-emission strategies, carbon capture will feature prominently in the power sector plans of nations that intend to meet their net-zero commitments. The next decade will be decisive in determining how quickly these technologies scale and whether they can deliver on their promise of affordable, reliable, and near-zero-emissions electricity from natural gas.