Currently, the dominant method for producing steel from iron ore still relies on fossil fuels as reducing agents. However, as new technologies are being implemented in pilot and commercial-scale facilities, a significant shift toward low-carbon steel production can begin within the next decade.  

Reliance on fossil fuels has defined the steel industry’s past as a major emitter of greenhouse gases; however, we are committed to a low-carbon future, which will require a transformation in the way we manufacture iron and steel.  

There is no single solution to enable low and near-zero steelmaking, and a broad portfolio of technological options is required, to be deployed alone or in combination as local circumstances permit. Our industry is leading much research, development and deployment (RD&D) efforts globally to develop each of these options.

 These new approaches fall into three broad categories:  

Below, we provide details on the different options, explore their current scope, opportunities, and challenges. 

Click on your technology of interest or the ‘Applications’ tag to see examples of how they are applied.

What is biomass?

Biomass is a renewable organic material derived from plants and animals, containing stored chemical energy from the sun. Plants produce biomass through photosynthesis. 

Biomass can be burned directly for heat, converted to renewable liquid and gaseous fuels through various processes, or used in industrial processes such as steelmaking. 

Why consider biomass in steelmaking?

Under the right circumstances, biomass can be considered a carbon-free resource; therefore, it can be an attractive option to reduce emissions from iron and steel production. 

The International Energy Agency’s (IEA) bioenergy programme notes that “within the biospheric carbon cycle, bioenergy can be carbon neutral because the carbon that is released during combustion has previously been sequestered from the atmosphere and will be sequestered again as the plants regrow, i.e. if sustainably produced. 

However, the whole supply chain must be considered, and all emissions associated with the production, processing, transport and use of bioenergy need to be included. Particularly, harvesting, transport, and processing generally involve fossil energy use. 

Nevertheless, analysis shows that the fossil energy used in the supply chain is generally a small fraction of the energy content of the bioenergy product, even for woody biomass transported over long distances, e.g. between North America and Europe.” 

Biomass is already used to a significant degree in the power sector. For example, the former Drax coal-fired power plant in North Yorkshire, England, converted four of the power station’s six generating units to use sustainable biomass instead of coal. This has transformed Drax, which supplies around 5% of the country’s electricity, into the UK’s largest renewable power generator and the biggest decarbonisation project in Europe.  

Biomass in iron and steelmaking

While some blast furnaces do currently operate entirely using biomass, the relative strength of charcoal compared to coke means that these are smaller furnaces. Charcoal is currently used commercially to substitute for a proportion of the coal used in blast furnaces, primarily in Brazil. 

Biochar can potentially be substituted for pulverised coal, which is currently injected directly into blast furnaces. 

Work was undertaken to this end under the Australian CO₂ breakthrough programme, which focused on substituting coal used in pulverised coal injection (PCI) in the blast furnace with sustainable biochar. 

Some developments continue to optimise charcoal production further to improve its product specifications for steel production. 

Opportunities and challenges

Sustainable biomass

Biomass can be cultivated sustainably by steel companies or acquired from third-party growers. In either case, a number of stewardship initiatives to support users of biomass exist; these have been developed by global bodies such as the Forest Stewardship Council and Sustainable Biomass Program (certification scheme designed for woody biomass). 

Regional schemes include the European Programme for the Endorsement of Forest Certification, the American Sustainable Forestry Initiative and the Brazilian CERFLOR programme. Legislative frameworks and regulations can also ensure forests are managed responsibly. 

Challenges

Increasing demand for bioenergy feedstock is leading to conflicts, with differing demands on land use. Competition for arable lands required for food and fibre production is the major issue concerning biomass production. 

Soil disturbance, nutrient depletion and impaired water quality are also potential environmental effects from biomass feedstock production and utilisation of agricultural and forest residues for energy. (reference) 

The bioenergy industry has responded to these concerns by developing the Sustainable Biomass Verification Scheme, which can be used as a manual for accrediting the sustainability of biomass for energy. Another more recent certification programme is the Sustainable Biomass Programme. 

Supply chain developments

Robust supply chains exist to move the large amounts of raw materials (such as coal, iron ore, lime, and scrap) required in modern steelmaking. 

Similar supply chains will need to be developed to harvest biomass at volume, convert and process it to char, and deliver it reliably to steel manufacturing facilities. Transportation and processing will also generate greenhouse gas emissions. 

Taking an LCA approach to assessing emissions for biomass use is crucial in obtaining a balanced view of the impact of biomass use on steel production. 

The World Bioenergy Association has prepared a fact sheet focused on supply chain issues. 

What is CCS?

Carbon capture and storage (CCS) refers to a suite of technologies that capture waste CO₂, typically from large point sources, transport it to a storage site, and deposit it in a location where it will not enter the atmosphere. 

Stored CO₂ is injected into an underground geological formation; this could be a depleted oil and gas reservoir or other suitable geological formation. CO₂ can also be injected into mature oil fields, driving out additional oil from the rock before being permanently stored. This is known as enhanced oil recovery (EOR) and is a form of carbon capture use and storage (CCUS). 

CCS in the steel industry

Potential approaches

CCS could potentially be applied to all major point sources in the steel sector. Past studies have tended to focus on the blast furnace as the major point source of CO₂ in a conventional integrated steel plant, either using retrofitted CO₂ capture technology or by developing a new type of blast furnace. The European ULCOS programme represents a good example of the latter, proposing a radical new top gas recycling blast furnace design.  

There is a CCS/CCUS project at the Baotou Iron and Steel (Group) Co., Ltd. (BISCO) in Baotou, Inner Mongolia, China. This project is recognised as China’s first full-chain CCUS project within the steel industry. The project aims to reduce carbon dioxide emissions from the steel production process by capturing and utilising or storing the captured carbon. 

Direct reduction plants can offer an easier route to CCS, as some plants incorporate CO2 separation into their designs and emit a concentrated stream of CO2 during normal operation. In these plants, additional carbon capture equipment is not required. 

Carbon capture can potentially be retrofitted to conventional iron and steelmaking facilities. 

Innovative coal-based smelt reduction plants, such as the HIsarna process piloted at Tata Steel in the Netherlands, can produce concentrated steam of CO₂, negating the need for CO₂ capture technology.  

Challenges

Scale up

The energy intensity of the capture process and associated costs continue to be a challenge. There are other challenges, such as the need for high-purity CO₂ streams (particularly for liquid-based CO₂ shipping) and space constraints when retrofitting existing plants.

The current CCS deployment is capital-intensive; however, through policy intervention and learning-by-doing that drives cost reductions, it can become competitive with other decarbonisation mechanisms.

Infrastructure

One of the challenges that CCS faces is how to transport significant volumes of compressed CO₂ from point sources to sites established for large-scale storage, especially offshore.

Pipelines are one solution, but their viability depends on access to land, the volume to be transported and whether the CO₂ comes from a variety of dispersed sources.

The other option is to use dedicated sea tankers that can deliver CO₂ from one or more ports, either directly to an offshore storage site, or an intermediate shore-based facility connected via pipeline to the storage site. 

The Northern Lights project is based on a model of shipping CO₂ from coastal sites around the North Sea to their storage facilities in Norway.   

Public acceptance

CCS is not universally embraced, and public perception and acceptance remain a bottleneck for its broad deployment. Many environmental NGOs dismiss CCS as high risk, unproven and fundamentally unnecessary. 

Local communities have also rejected CCS, citing concerns around safety and impact on property value, though this varies by region. In many areas with a history of exploiting the subsurface (e.g. Saudi Arabia, Texas), community concern is low; however, in Europe, development of CO₂ storage is now largely offshore. 

Evidence suggests that community concerns can be managed, but with significant effort from the project developer.  

Costs

The IEA found that innovative process routes (including CCS on the blast furnace, smelt reduction and gas-based DRI) can be expected to cost 10-50% more than conventional technology within a given regional context, noting this cost increase significantly exceeds profit margins from steelmaking today. 

Regulatory issues

While regulation of carbon capture and storage (CCS) has progressed in some regions, it remains uneven globally. In the European Union, a robust legal framework is already in place through the EU CCS Directive (2009/31/EC), which governs site selection, permitting, monitoring, and long-term liability. The EU Emissions Trading System (EU ETS) also recognises geological storage of CO₂, providing mechanisms for quantification, verification, and crediting of stored emissions. 

However, many jurisdictions worldwide still lack comprehensive CCS or CCUS (carbon capture, utilisation, and storage) legislation. In these regions, key regulatory components—such as storage permitting, long-term liability management, cross-border CO₂ transport, and monitoring standards—are either under development or absent.

This regulatory fragmentation poses a barrier to investment and large-scale deployment, especially in emerging economies and regions without prior experience in subsurface resource management. 

What is CCUS?

As is the case with carbon capture and storage (CCS), CCUS technologies separate and capture the CO₂ generated during the iron and steelmaking process. The difference is that using CCS, the CO₂ is stored permanently.  

Using CCUS technologies, the CO₂ can be chemically converted into other products such as plastics, concrete or biofuel, or used in enhanced oil recovery (EOR). 

Why consider CCUS?

CCUS technologies can add significant strategic value in the transition to net-zero:

• CCUS can be retrofitted to existing power and industrial plants, which could otherwise still emit 8 billion tonnes (Gt) of CO₂ by 2050.
• CCUS can tackle emissions in sectors where other technology options are limited, such as in the production of cement, iron and steel or chemicals, and to produce synthetic fuels for long-distance transport (notably aviation).
• CCUS is an enabler of least-cost low-carbon hydrogen production.
• CCUS can remove CO₂ from the atmosphere by combining it with bioenergy or direct air capture to balance emissions that are unavoidable or technically difficult to abate.
• CCUS can enable investment in shared infrastructure and the development of capture technology.

Challenges and opportunities

Permanent carbon reduction potential

In many cases, CCUS products, such as synthetic fuels, are combusted and the carbon contained within them is released to the atmosphere as CO₂. Some stakeholders argue that these applications merely delay the release of CO₂ unless a corresponding reduction in fossil-based emissions occurs. 

At the same time, wider use of CCUS syn-fuels would reduce the need to extract natural resources from potentially fragile ecosystems and reduce the need to transport large quantities of fossil fuels, with the associated emissions and environmental risks. 

It is possible to use synthetic fuels as a medium to store the output of variable renewables (for example, the Sunfire Project) if CCUS-based synthetic fuels are combined with direct air capture technology (DAC). 

It will be important to ensure that carbon accounting rules applied to the entire CCUS system are credible and take a life cycle approach to accurately assess the positive and negative impacts of CCUS technology.  

Other CCUS applications

Applications other than synthetic fuels are being considered; these include oxygenated compounds (polycarbonate, urethane, etc.), biomass-derived chemicals, commodity chemicals (olefin, BTX, etc.), minerals such as concrete products, concrete structures, carbonate, etc. 

Scale and impact

Achieving emission reductions commensurate with the IEA’s Net Zero Scenario will require global emissions to fall by over 30Gt per year. It seems unlikely that CCUS applications on their own will be capable of making a material impact. 

However, growth in CCUS will enable the further development of CO₂ capture technology and the deployment of CO₂ transportation infrastructure. 

Many steel plants are located in industrial clusters in close proximity to other emitters, and a shared CO₂ transport and storage infrastructure that many industries can use could be an efficient and cost-effective way to meet climate targets. 

The IEA notes that ‘deployment strategies that shift the focus from large, stand-alone CCUS facilities to the development of industrial “hubs” with shared CO₂ transport and storage infrastructure are also opening up new investment opportunities.’ 

It is also possible to transition EOR facilities into CCS facilities, which have the potential to permanently sequester significant and material amounts of CO₂. 

Inert nature of CO₂

CO₂ is an inert gas, and converting it into any useful chemical or fuel will require energy to be used.

What is electrolysis?

Electrolysis is a technique that uses direct electric current to separate some chemical compounds into their constituent parts.

Electricity is applied to an anode and a cathode, which are immersed in the chemical to be electrolysed.

Electrolysis of water (H₂O) produces hydrogen and oxygen, whereas electrolysis of iron oxide (Fe₂O₃) produces iron and oxygen.

Why consider electrolysis in ironmaking?

There are two potential ways to separate metallic iron from the oxygen to which it is bonded in iron ore. These are through the use of chemical reductants such as hydrogen or carbon, or through the use of electrochemical processes that use electrical energy to reduce iron ore.

In electrolysis, iron ore is dissolved in a solvent and an electric current is passed through it.

Negatively charged oxygen ions migrate to the positively charged anode, and the oxygen bubbles off. Positively-charged iron ions migrate to the negatively-charged cathode, where they are reduced to elemental iron.

If the electricity used is carbon-free, then iron is produced without CO₂2 emissions. 

Electrolysis of iron ore has progressed beyond the laboratory scale, with pilot-scale demonstrations now producing metallic iron and oxygen as a co-product.

Opportunities and challenges

Scale up

A typical blast furnace is capable of making somewhere in the order of 2.5 Mt of iron in a year. 

To date, electrolysis processes have produced metallic iron in batches measured in kilograms. Achieving industrial relevance would require a scale-up of approximately eight orders of magnitude — a substantial challenge for commercial deployment.

The IEA’s iron and steel roadmap noted ‘direct electrification of steelmaking through electrolysis is not included in the Sustainable Development Scenario due to its comparatively low Technology Readiness Level (TRL). Leading electrolysis projects are at TRL level of around 6–7. However, with accelerated progress on innovation, electrolysis could play a role in sustainable steelmaking in the longer term.’

Under the IEA’s illustrative ‘Faster Innovation Case’, a scenario aimed at exploring the feasibility of bringing forward net-zero emissions for the energy system as a whole to 2050 is foreseen by accelerating work on clean energy technology innovation electrolysis, which plays a more meaningful role.

IEA modelling suggests that under these extreme conditions, 100 Mt of iron ore electrolysis could conceivably be in operation by 2050. The IEA notes that there is scant precedent for the very rapid pace of innovation required in the Faster Innovation Case.

Energy availability

Since electrolysis produces no CO₂, it could theoretically be zero-carbon, but only if the electricity needed to power the process is generated without causing emissions, and that electrode consumption does not lead to CO₂ emissions.

A significant increase in low-carbon electricity generation capacity would be required to install electrolysis-based ironmaking at scale. Boston Metals has set a target of 4MWh per tonne of steel.

If this were to be achieved, and the IEA’s extreme 100 Mt example came to pass, this would need to be supported by 46GW of low-carbon generational capacity, which would be the equivalent of 5,500 of the world’s most powerful offshore wind turbines, or 28 1.6GW nuclear reactors.

Metallurgy

Unlike iron produced using conventional ironmaking techniques, electrolysed iron will be chemically pure, being formed of practically 100% Fe.

Blast furnace iron (hot metal) is typically up to 5% carbon and contains a number of impurities (typically 0.6 to 0.8 percent silicon, 0.03 percent sulphur, 0.7 to 0.8 percent manganese, and 0.15 percent phosphorus) that must be refined during primary and secondary steelmaking to a level suitable for the final grade.

Typical ranges of DRI chemistry are 90–94% total iron, 83–89% metallic iron, 6.5–9% iron oxide, 0.8–2.5% carbon, 2.8–6% gangue, 0.005–0.09% phosphorus, and 0.001–0.03% sulphur. Gangue needs to be removed in the EAF or converter units. 

Being pure, electrolysed iron represents a ‘blank canvas’, and alloying elements (including carbon) will need to be added to it to achieve the desired properties. This could be an advantage, with very precise control of final steel chemistry being possible. 

Electrodes

Several engineering problems still need to be solved before iron electrolysis becomes economically viable. These include the development of a cheap, carbon-free inert anode that is resistant to the corrosive conditions in molten oxide electrolysis.

Flexibility

Like an EAF, but unlike a blast furnace, electrolysis-based production can be scaled up and down more easily to reflect the availability of renewable energy sources (such as solar and wind) and electricity prices.

What is hydrogen-based reduction?

Direct reduction of iron is the chemical removal (reduction) of oxygen from iron ore in its solid form.

The iron used in the steelmaking process is currently chemically reduced from iron ore through the use of fossil resources – natural gas or coal. This process is known as Direct Reduced Ironmaking (DRI).

Carbon combines with the oxygen in the iron ore, producing metallic iron and a carbon-rich process gas, according to the following simplified chemical reaction:

2Fe₂O₃ + 3C -> 4Fe + 3CO₂

It is also possible to reduce iron ore using hydrogen instead of carbon; in this case, the waste gas produced is water, as per the following reactions:

Fe₂O₃ + 3H₂ -> 2Fe + 3H2O , FeO +H₂ -> Fe + H₂O

H₂ production and use now

Hydrogen can be extracted from hydrogen-bearing fuels, such as natural gas and biogas, and from water using electrolysis.

The primary source of hydrogen production is currently natural gas, accounting for around three-quarters of the annual global dedicated hydrogen production of around 70 million tonnes.

This accounts for about 6% of global natural gas use.

Currently, less than 0.1% of global dedicated hydrogen production comes from water electrolysis.

H₂ in the steel industry now

In natural gas-based DRI production, hydrogen does play a role in the reduction process, though this is in combination with carbon.

Greenhouse gas (GHG) emissions from gas-based DRI production are lower than from the BF route, leading to the emission of 1.43 tonnes of CO₂ per tonne of crude steel, compared to 2.32 tonnes from the BF (based on worldsteel 2023 calculation).

Pure hydrogen is not currently used in ironmaking applications outside of pilot and experimental facilities.

Potential approaches

There are three main sources of hydrogen. ‘Green’ or ‘pink’ hydrogen is produced by combining low-carbon energy with electrolysis, ‘blue’ hydrogen is produced from fossil fuels in a facility equipped with carbon capture and storage (CCS), and ‘grey’ hydrogen comes from unabated fossil fuel.

In its 2020 technology roadmap, the International Energy Agency (IEA) suggests that under its Sustainable Development Scenario (SDS), green hydrogen is introduced as a primary reducing agent at a commercial scale in the mid-2030s.

Use expands to 12 Mt per year by 2050. While this represents a fast scale-up and deployment of a new technology, the IEA’s modelling suggests that by 2050, under 8% of total steel production will rely on electrolytic hydrogen as the primary reducing agent (or 14% of primary production).

Challenges

Scale up

The IEA also expects that by 2050, the greatest demand for electrolytic hydrogen in steel is expected in India and China (just over 4.5 Mt of hydrogen in each) due to large production volumes and access to large amounts of low-cost renewable electricity.

Around 70 Mt of dedicated hydrogen is produced today, 76% from natural gas and almost all the rest (23%) from coal. Less than 0.1% of global dedicated hydrogen production today comes from water electrolysis.

If all current dedicated hydrogen production were produced through water electrolysis (using water and electricity to create hydrogen), this would result in an annual electricity demand of 3,600 TWh – more than the annual electricity generation of the European Union.

Under IEA’s Sustainable Development Scenario (SDS), global demand for hydrogen rises to 287Mt by 2050, representing an increase of over 400% from 2020. This presents a massive scale-up challenge.

Infrastructure

As a light and molecularly small gas, hydrogen can be difficult to contain, and specialised infrastructure will need to be developed to enable storage and distribution at scale.

There are close to 5,000 km of hydrogen pipelines around the world today, compared with around 3 million km of natural gas transmission pipelines.

Existing high-pressure natural gas transmission pipes could be converted to deliver pure hydrogen in the future if they are no longer used for natural gas, but their suitability must be assessed on a case-by-case basis and will depend on the type of steel used in the pipeline and the purity of hydrogen being transported.

A further challenge is that three times more volume is needed to supply the same amount of energy as natural gas.

Additional transmission and storage capacity across the network might therefore be required.

Electrolysis requires water as well as electricity. Around 9 litres of water are needed to produce 1 kg H₂, producing 8 kg of oxygen as a co-product. This could be a challenge in water-stressed areas.

Costs

The IEA found that innovative process routes (including CCS on the BF, smelt reduction and gas-based DRI) can be expected to cost 10-50% more than commercially available counterparts within a given regional context, noting this cost increase significantly exceeds profit margins from steelmaking today.

The IEA analysis found that the cost of producing hydrogen from renewable electricity could decrease by 30% by 2030, due to declining costs of renewables and the scaling up of hydrogen production.

Safety issues

Like other energy carriers, hydrogen presents certain health and safety risks when used on a large scale.

As a light gas composed of small molecules, hydrogen requires specialised equipment and procedures for handling it.

Hydrogen is so small it can diffuse into some materials, including some types of iron and steel pipes, and increase their chance of failure. It also escapes more easily through sealings and connectors than larger molecules, such as natural gas.

Hydrogen can also lead to embrittlement and cracking in steel pipes and vessels. Austenitic stainless steels are not susceptible to hydrogen embrittlement.

Hydrogen is highly flammable and can ignite over a wide range of concentrations in air (4–75%), with a very low ignition energy, making unintentional releases particularly hazardous in enclosed or poorly ventilated areas. 

Steelmakers are already developing and deploying Process Safety Management systems to manage the risk associated with the loss of containment of hazardous materials, toxic or flammable.

Risk assessments and associated controls will need to be updated to incorporate risks associated with hydrogen use when it is used.