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Lower-carbon steel is not one interchangeable material or a single technology. It is steel made with production routes and supply-chain choices that emit less greenhouse gas than the coal-based blast furnace-basic oxygen furnace (BF-BOF) benchmark. The main options are scrap-based electric arc furnaces (EAFs), direct-reduced iron (DRI) melted in an EAF, and conventional or alternative ironmaking with carbon capture, use and storage (CCUS). Material efficiency and recycling reduce demand for new iron, but they do not eliminate the need for primary steelmaking.
The lowest practical result depends on the furnace route, scrap or ore input, electricity emissions, hydrogen or natural-gas supply, methane leakage, capture and storage performance, and the accounting boundary. A credible purchase specification therefore asks for a verified product-level emissions figure, its scopes and system boundary, feedstock mix, energy assumptions, and the method used to calculate it.
What “lower-carbon steel” means
Steel production has two broad tasks: turn iron-bearing material into iron, then refine and alloy that iron into a finished steel product. The conventional route performs the first task in a blast furnace using coke and other coal-based fuels, then uses a basic oxygen furnace to make steel. Because the blast furnace removes oxygen from ore with carbon and supplies heat by combustion, it is inherently emissions-intensive.
Lower-carbon routes reduce emissions by changing one or more of four elements:
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- Ironmaking chemistry: using hydrogen or natural gas instead of coal as the principal reducing agent, or capturing carbon dioxide from the process.
- Metallic feedstock: melting more recycled scrap or using DRI, hot-briquetted iron (HBI), or other iron units with a different emissions profile.
- Energy: supplying an electric arc furnace, hydrogen electrolyzer, or other equipment with low-emissions electricity.
- Demand: designing products efficiently, extending service life, reusing components, and recycling steel at end of life.
“Green steel” is not a precise emissions category by itself. Treat that label as a starting point, not proof of a specific footprint. A supplier should state the emissions boundary, gases counted, allocation method, production date, route, energy sources, and a verified tonnes-of-CO2-equivalent-per-tonne figure.
The conventional benchmark: BF-BOF
The blast furnace-basic oxygen furnace route remains the largest global steelmaking route. The International Energy Agency reported in its 2025 Breakthrough Agenda Report that it represented about 70% of global steel production. Iron ore, coke and other materials enter the blast furnace; the coke supplies both heat and the chemical carbon needed to remove oxygen from the ore. The resulting hot metal goes to a basic oxygen furnace, where oxygen lowers its carbon content and scrap is often added as a coolant and iron source.
Efficiency projects can lower the route’s emissions without changing its basic design. Examples include improved furnace operation, waste-heat recovery, higher scrap additions to the BOF charge, less carbon-intensive fuels where technically possible, and CCUS. These measures do not turn BF-BOF into a zero-emissions process: ore reduction still creates process emissions, and capture equipment consumes energy and leaves residual emissions.
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Route comparison at a glance
| Route | How it works | Main emissions lever | Important limitations |
|---|---|---|---|
| BF-BOF | Coal-based blast furnace reduces ore; basic oxygen furnace refines hot metal, usually with some scrap. | Efficiency, more scrap in the BOF charge, fuel changes and CCUS. | Still an ore-based, carbon-intensive route; capture performance depends on the source stream, energy penalty and storage. |
| Scrap-EAF | Scrap is melted and refined with electricity in an electric arc furnace; DRI or other iron units may supplement the charge. | Low-emissions electricity and a high share of suitable scrap. | Scrap availability, quality and contamination constrain output; electricity and charge mix determine the result. |
| Natural-gas DRI-EAF | Ore is reduced in the solid state, commonly with natural gas, then melted and refined in an EAF, often with scrap. | Efficient operation, lower-emissions power and eventual conversion toward hydrogen. | Emissions include gas production and possible methane leakage; it remains an ore-based route. |
| Hydrogen DRI-EAF | Hydrogen is the principal reducing agent in a DRI shaft furnace; an EAF makes the steel. | Low-emissions hydrogen and electricity. | Early deployment needs hydrogen, power, transport and storage infrastructure; cost and availability vary by region. |
| CCUS-enabled routes | Capture equipment is fitted to emissions streams from steelmaking or an alternative ironmaking process. | Permanent storage of captured carbon dioxide. | Residual emissions, capture boundaries, energy use and dependable transport and storage must be disclosed. |
Scrap-based electric arc furnaces
Process and emissions profile
An EAF uses electric arcs to melt metallic feedstock. In a scrap-EAF mill, that feedstock is mainly post-consumer or industrial steel scrap, with oxygen, carbon and alloying additions used to control chemistry. The route avoids the blast furnace’s coal-based reduction step, so its direct process emissions can be much lower. Electricity, electrode consumption, natural-gas burners and downstream finishing still contribute to the footprint.
World Steel Association route indicators illustrate the potential difference. Its 2024 expanded greenhouse-gas indicator, reported in 2025 and updated in February 2026, lists average intensities of 2.66 tonnes CO2e per tonne of crude steel for BF-BOF and 0.71 tonnes CO2e per tonne for scrap-EAF. The same table reports that the BF-BOF category contains about 10% scrap, while the scrap-EAF category contains more than 70% scrap. Those different charge mixes are part of the reason the averages are not interchangeable plant-to-plant. See the World Steel Association Sustainability Indicators Report 2025.
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Why electricity matters
Calling an EAF “electric” does not make it automatically low-carbon. A furnace supplied by coal-heavy electricity can have a substantially higher footprint than one supplied by a grid or contracted generation with low emissions. A purchase specification should request the electricity emissions factor, whether it is location-based or market-based, the accounting period, and any certificates or contracts used to support the claim.
Scrap quality and availability
Scrap is not a uniform commodity. Post-consumer scrap can contain copper, tin, chromium, coatings or other residual elements that are difficult to remove in an EAF. High-quality flat steel often requires clean, sorted scrap or additional virgin iron units to meet tight chemistry limits. Collection rates, demolition cycles, manufacturing scrap and regional trade determine how much suitable material is available.
Recycling also cannot supply all future demand. Steel stocks in buildings, vehicles, machinery and infrastructure remain in use for years or decades, so the amount of scrap generated at any moment is limited by past production. The IEA and World Steel Association therefore describe recycling and ore-based production as complementary rather than interchangeable. Life-cycle context is explained by the association’s About life cycle thinking page.
Natural-gas DRI followed by EAF
How DRI changes ironmaking
Direct reduction removes oxygen from iron ore without melting the ore first. A shaft furnace exposes pellets or lump ore to a reducing gas, producing solid metallic iron. That DRI can be hot-charged or briquetted, transported, and melted in an EAF, commonly with scrap. Because the reduction reaction and melting are separated, the plant can use a different reducing agent from a blast furnace.
Natural-gas DRI generally emits less than BF-BOF when the gas is efficiently used and the electricity supply is not carbon-intensive. However, it is not emissions-free. The footprint includes carbon dioxide from reforming or burning gas, upstream production emissions and methane leakage, electricity for the EAF and auxiliaries, and emissions associated with ore preparation and transport. Supplier data should identify the gas source, leakage assumptions, DRI metallization, scrap share and power factor.
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Why it can be a transition route
Many DRI plants can be designed or modified to use increasing proportions of hydrogen as infrastructure and supply develop. A natural-gas plant may therefore provide a pathway toward hydrogen DRI, but the transition is not automatic. Reactor design, burners, compressors, storage, pipelines, pellet quality and electricity capacity can all limit the feasible hydrogen share.
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Climate benefit depends on both hydrogen and power
In hydrogen DRI, hydrogen removes oxygen from ore and produces water vapor rather than carbon dioxide at the reduction reaction. The resulting iron is melted in an EAF. The pathway has the greatest climate benefit when hydrogen is made with low-emissions electricity or another demonstrably low-emissions process and when the EAF and auxiliary equipment also use low-emissions power.
Hydrogen made from unabated fossil gas, or electricity generated with high emissions, can substantially reduce or even undermine the expected advantage. A credible claim should therefore identify hydrogen production technology, electricity source, emissions factor, transport losses, storage and the proportion of hydrogen actually used during the reported production period.
Readiness and cost
Hydrogen DRI-EAF is an emerging preferred low-emissions route in some regions, but commercial deployment is constrained by ore quality, electrolyzer or hydrogen supply, renewable-power availability, grid connections, storage and transport. The IEA’s 2025 Breakthrough Agenda Report estimates that early commercial plants using 100% hydrogen blends could cost 50–140% more than BF-BOF today, with the premium varying by region. This is an estimate for early commercial plants under regional assumptions, not an observed universal market price.
Projects may initially operate with a hydrogen blend or switch between natural gas and hydrogen. When comparing offers, ask whether the quoted emissions and price assume 100% hydrogen, a blend, future availability or a guaranteed supply contract. The IEA’s technology discussion is available at Breakthrough Agenda Report 2025: Steel, while World Steel Association background on hydrogen and other breakthrough processes appears at Breakthrough technologies.
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CCUS and alternative ironmaking
What capture can do
Carbon capture, use and storage can be applied to concentrated emissions streams from blast furnaces, direct-reduction plants, reformers or other process units. Captured carbon dioxide can be transported for permanent geological storage or, in some cases, used in products or processes. Only carbon that is captured, transported and permanently stored should be counted as removed from atmospheric emissions; temporary use is not equivalent to permanent storage.
Questions to ask about a CCUS claim
- Which process streams are covered, and what percentage of total site emissions do they represent?
- Is the reported number gross or net of capture-equipment energy, compression, transport and storage?
- What residual emissions remain from uncaptured gases, upstream fuels, electricity, ore preparation and transport?
- Where is the carbon stored, who operates the storage site, and how is permanence monitored?
- Are captured volumes measured and verified for the specific product batch or allocated across the plant?
CCUS can reduce emissions from existing assets and alternative ironmaking designs, but capture alone does not justify calling steel “zero-emissions.” The IEA’s Iron and Steel Technology Roadmap discusses capture alongside efficiency, recycling, direct reduction and other measures.
What the latest route numbers actually show
World Steel Association indicators provide useful benchmarks, provided their boundaries are kept distinct. Its 2024 expanded indicator includes scope 1, 2 and 3 greenhouse-gas components, including upstream mining. The association reported a 2024 global average of 2.18 tonnes CO2e per tonne of steel, based on 1,886 million tonnes of steel production, while sector emissions were about 4.1 billion tonnes CO2e. These figures are summarized in its Climate change and the production of iron and steel overview.
| 2024 route indicator | BF-BOF | Scrap-EAF | DRI-EAF | Global average |
|---|---|---|---|---|
| Expanded GHG intensity, tonnes CO2e per tonne of crude steel | 2.66 | 0.71 | 1.66 | 2.18 |
| CO2-only intensity, tonnes CO2 per tonne of crude steel | 2.34 | 0.69 | 1.47 | Not stated for this series |
| Typical scrap share in route category | 10% | More than 70% | Less than 30% | Route mix varies |
The expanded GHG series and the CO2-only series are different indicators. Do not present 2.34, 0.69 or 1.47 as if they were the same measurements as 2.66, 0.71 or 1.66. The route averages also combine plants with different ore grades, scrap quality, electricity supplies, operating efficiencies and product mixes. They are useful for orientation, not a substitute for a supplier’s product-specific declaration.
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1. Match the emissions boundary
Determine whether each figure covers direct plant emissions only, scopes 1 and 2, or scopes 1–3. Check whether mining, pelletizing, transport, purchased reductants, capital goods and end-of-life recycling are included. Life-cycle studies may use different functional units and allocation rules, so two numbers with the same units can still describe different systems.
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2. Identify the metallic charge
Request the percentages of scrap, DRI, HBI, pig iron and other iron units. A nominal “EAF” label can describe a mostly scrap charge, a DRI-rich charge, or a mixture. The charge affects both emissions and the ability to meet chemistry requirements.
3. Check energy assumptions
For EAF steel, obtain the electricity emissions factor and accounting method. For DRI, ask whether the reducing gas is natural gas, hydrogen or a blend; identify hydrogen production and power sources; and request methane-leakage assumptions for gas-based production. For CCUS, include compression and storage energy.
4. Confirm verification and allocation
Ask for an independently verified environmental product declaration or equivalent product-level document where available. Confirm the production site, reporting year, allocation method, mass-balance rules, recycled-content definition and whether certificates are bundled, unbundled or averaged across multiple facilities.
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5. Separate current performance from future intent
A plant that plans to convert to hydrogen, add capture or procure cleaner electricity should not report the future result as today’s footprint. Record the operating route and energy sources for the delivery period, then treat planned improvements as separate, dated commitments.
Availability, cost and infrastructure trade-offs
| Decision factor | Scrap-EAF | Natural-gas DRI-EAF | Hydrogen DRI-EAF | CCUS-enabled route |
|---|---|---|---|---|
| Key input constraint | Suitable scrap and low-emissions electricity. | DRI-grade ore, natural gas, electricity and scrap. | DRI-grade ore, large low-emissions hydrogen and electricity supplies. | Concentrated CO2 stream, energy, transport and secure storage. |
| Typical readiness | Commercial and widely deployed, with regional variation. | Commercial in several regions. | Early commercial deployment; infrastructure is developing. | Site-specific commercial or demonstration deployment. |
| Main cost exposure | Power prices, grid charges, scrap premiums and electrode costs. | Natural-gas prices, gas emissions, ore pellets and power. | Hydrogen and clean-power prices, electrolyzer and infrastructure costs. | Capture plant, energy penalty, transport and storage fees. |
| Carbon result most sensitive to | Electricity factor and scrap quality or contamination. | Gas production and leakage, power and charge mix. | Hydrogen and electricity emissions and utilization. | Capture rate, residual emissions and verified permanent storage. |
Local conditions can reverse a simple route ranking. A scrap-EAF in a region with limited clean power may not outperform a well-operated DRI-EAF supplied with lower-emissions energy. Conversely, abundant clean electricity and high-quality scrap can make EAF production especially attractive. Transporting scrap, pellets, hydrogen or finished steel also changes the life-cycle result.
Material efficiency and recycling are part of the solution
Producing less steel for the same service is an emissions measure alongside changing the furnace. Designers can reduce unnecessary mass, standardize components for reuse, extend building and vehicle life, repair equipment, and avoid over-specifying strength or thickness. Better collection, sorting and remelting preserve material value when products reach end of life.
These actions complement rather than replace primary ironmaking. Steel demand can grow faster than the stock of recoverable scrap, and some applications require low-residual iron units that scrap streams cannot supply. The IEA’s demand and supply analysis describes material efficiency, recycling and production changes as a portfolio; its executive summary is available at Demand and Supply Measures for the Steel and Cement Transition.
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When scrap-EAF is a strong fit
- Your region has reliable supplies of suitably sorted scrap.
- The grid or contracted electricity has a documented low emissions factor.
- The product tolerates the residual-element profile of the available scrap, or the mill can add clean DRI or other iron units.
- You can obtain a verified product-level footprint for the actual melt shop and delivery period.
When DRI-EAF is useful
- You need more virgin iron than local scrap markets can provide.
- DRI-grade pellets and natural gas or hydrogen are available with documented emissions data.
- The plant can secure low-emissions electricity and has a credible plan for hydrogen conversion if that is part of the specification.
When to consider CCUS
- An existing ore-based plant has a concentrated stream suitable for capture.
- CO2 transport and permanent storage are operating or contractually secured.
- The supplier can report capture rate, residual emissions and net product intensity rather than only the volume captured.
What every buyer should put in the contract
- Specify the route, site, product grade and delivery period.
- Require a tonnes-CO2e-per-tonne figure with the scopes, gases, system boundary and allocation method.
- List scrap, DRI, HBI, pig iron and other charge proportions or acceptable ranges.
- State electricity, hydrogen and natural-gas accounting requirements, including methane assumptions where relevant.
- Require independent verification and a process for reporting changes in route, energy source or feedstock.
- Define how missed emissions thresholds, certificate substitutions and mass-balance claims will be handled.
Bottom line
The most established lower-carbon alternatives are scrap-EAF where clean power and suitable scrap are available, natural-gas DRI-EAF as a lower-emissions ore-based route that can move toward hydrogen, and hydrogen DRI-EAF where low-emissions hydrogen and electricity can be secured. CCUS can reduce emissions from existing or alternative ironmaking but must be reported with capture boundaries, residual emissions and permanent-storage evidence. No route is automatically low-carbon by name alone. Compare the actual feedstock, energy, boundary and verified product footprint before treating one offer as lower-carbon than another.
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