DRI-EAF Economics for Indian Steel: The Natural Gas Bridge to Hydrogen and What the Numbers Actually Say
Direct Reduced Iron with natural gas reduces Scope 1 emission intensity to 0.8–1.4 tCO₂/t crude steel — a 60–70% reduction versus BF-BOF. The transition from natural gas DRI to hydrogen DRI requires no new reactor — only a feedstock switch. For Indian steel producers facing CBAM costs of €60–165/t over the next decade, this pathway changes the EU market economics entirely.
Key Takeaways
- Direct Reduced Iron (DRI) is produced by reducing iron ore with a reducing gas — removing oxygen from iron oxide without melting it — at temperatures of 800 to 950°C. Natural gas reforming (producing a H₂-CO syngas via the Midrex or HYL/Energiron process) is the dominant DRI technology globally. Coal-based DRI (via the rotary kiln process) dominates India’s DRI production, accounting for approximately 75 to 80 percent of India’s annual output of approximately 38 to 40 million tonnes — the highest DRI production of any country. Coal-based DRI produces approximately 2.5 to 3.0 tCO₂/t DRI — not meaningfully lower than BF-BOF on a gate-to-gate basis. Natural gas DRI produces approximately 0.9 to 1.2 tCO₂/t DRI — and hydrogen DRI produces approximately 0.1 to 0.2 tCO₂/t DRI when produced with green hydrogen from renewable electricity.
- The CBAM-relevant metric is Scope 1 emission intensity of crude steel — not of DRI. In a DRI-EAF route, the Scope 1 embedded emission of crude steel is the sum of the DRI production emission (from the reducing gas) and the EAF steelmaking emission (from electrode combustion and auxiliary fuel use). For natural gas DRI-EAF, this combined Scope 1 intensity is approximately 0.8 to 1.4 tCO₂/t crude steel — significantly below India’s BF-BOF average of 2.1 to 2.3 tCO₂/t and below the EU CBAM benchmark of approximately 1.37 tCO₂/t for primary steel. Natural gas DRI-EAF steel therefore carries a near-zero or zero CBAM obligation on EU exports — a transformation of the EU market economics for Indian producers operating this route.
- The hydrogen upgrade pathway is the most important technical feature of the Midrex and HYL/Energiron natural gas DRI processes. Both are designed to accept hydrogen blending into the reducing gas — up to 100 percent hydrogen in the case of Midrex H₂ and Energiron ZR (zero reformer) configurations. This means that a plant built today for natural gas DRI can transition progressively to hydrogen DRI by substituting hydrogen for natural gas in the reducing gas mix, without replacing the shaft furnace reactor. The capital cost of the hydrogen transition from a natural gas DRI plant is therefore only the cost of the hydrogen supply infrastructure (electrolyser, storage, compression) — not a new reactor.
- India’s current natural gas DRI capacity is approximately 5 to 7 million tonnes per year, concentrated at JSPL’s Raigarh and Angul plants, Essar Steel’s Hazira plant (now operated by ArcelorMittal Nippon Steel), and smaller plants in Gujarat and Andhra Pradesh. This capacity represents approximately 12 to 18 percent of India’s total DRI output — and it carries the emission profile that makes natural gas DRI-EAF competitive in the EU market even without hydrogen transition.
- The Viksit Bharat steel capacity target of 300 MMT by 2047 — up from approximately 150 MMT today — implies adding 150 million tonnes of new steelmaking capacity over the next two decades. Every increment of that new capacity that is built on natural gas DRI-EAF rather than BF-BOF reduces India’s structural CBAM exposure in the 2030s and 2040s while creating a hydrogen-ready production footprint that can transition to green steel as H₂ costs decline. The capacity decisions taken in 2026 to 2030 determine India’s 2040 steel sector emission trajectory.
- JSPL’s Angul steel complex is the most advanced DRI-EAF operation in India, with an integrated DRI-EAF-thin slab casting line producing structural steel and flat products at emission intensities that are significantly below the BF-BOF fleet average. JSPL has announced plans to introduce hydrogen into its DRI process at Angul in alignment with the SIGHT programme — making it the most likely first commercial scale hydrogen-DRI site in India’s steel sector.
India is the world’s largest producer of Direct Reduced Iron. Producing 38 to 40 million tonnes per year — more than the next three countries combined — India has built a DRI manufacturing base that is structurally positioned to lead the global transition to hydrogen-based ironmaking. The challenge is that India’s DRI leadership is predominantly in the wrong technology variant. Approximately 75 to 80 percent of India’s DRI is produced through coal-based rotary kiln processes — a technology that reduces iron oxide with coal-derived reducing gases and produces DRI with an emission intensity of 2.5 to 3.0 tCO₂/t DRI, barely lower than the blast furnace route it is notionally replacing.
The natural gas DRI processes — Midrex and HYL/Energiron, which produce DRI in a shaft furnace using reformed natural gas as the reductant — carry an emission intensity of approximately 0.9 to 1.2 tCO₂/t DRI, approximately 60 to 70 percent below the coal-based alternative. In the context of CBAM — which covers the Scope 1 embedded emissions of the crude steel produced from the DRI, not the DRI itself — this intensity difference translates directly into a near-zero CBAM obligation for natural gas DRI-EAF steel exported to the EU. For Indian steel producers making the BF-BOF versus DRI-EAF route decision for their next capacity increment, this CBAM calculus is now the financially dominant variable.
The emission intensity comparison: gate-to-gate for crude steel
Natural Gas DRI-EAF Route: DRI shaft furnace (natural gas reforming, CO₂ in off-gas): ~0.65–0.90 tCO₂/t crude steel EAF steelmaking (electrode combustion + auxiliary fuel): ~0.10–0.15 tCO₂/t Casting and rolling auxiliary fuel: ~0.05 tCO₂/t Total Nat. Gas DRI-EAF Scope 1: ~0.80–1.10 tCO₂/t crude steel
Hydrogen DRI-EAF Route (100% green H₂ reductant): DRI shaft furnace (H₂ + iron ore → Fe + H₂O; near-zero CO₂): ~0.02–0.05 tCO₂/t EAF steelmaking (electrodes + scrap top-up): ~0.08–0.12 tCO₂/t Total H₂-DRI-EAF Scope 1: ~0.10–0.17 tCO₂/t crude steel
BF-BOF — CBAM Position April 2026
Natural Gas DRI-EAF — CBAM Position April 2026
The natural gas to hydrogen upgrade pathway
The most commercially important technical feature of the Midrex and HYL/Energiron processes is their hydrogen compatibility. Unlike coal-based rotary kiln DRI — which is a fundamentally coal-dependent technology with no hydrogen upgrade pathway — the shaft furnace processes used in natural gas DRI are designed around reducing gases that can contain varying hydrogen percentages. In a standard Midrex plant, the reducing gas exiting the reformer is approximately 55 percent H₂ and 36 percent CO by volume. As hydrogen is blended directly into the reducing gas (bypassing or supplementing the reformer), the CO₂ emissions from the DRI process fall proportionally.
At 30 percent hydrogen in the reducing gas blend, DRI shaft furnace Scope 1 emissions fall by approximately 20 to 25 percent from the pure natural gas baseline. At 70 percent hydrogen, emissions fall by approximately 55 to 60 percent. At 100 percent hydrogen — the Midrex H₂ and Energiron ZR configurations — shaft furnace CO₂ emissions approach zero, with only small amounts from electrode combustion in the EAF and auxiliary fuel use in casting and rolling. This progressive substitution capability means that steel plants can align their hydrogen transition pace precisely with the declining cost curve of green hydrogen — increasing hydrogen blend percentages as green hydrogen becomes cost-competitive at each threshold level.
Natural Gas DRI to Hydrogen DRI — Emission Intensity at Progressive H₂ Blend Percentages
| H₂ Blend (% of reducing gas) | DRI Shaft Furnace CO₂ (tCO₂/t DRI) | Crude Steel Scope 1 (tCO₂/t) | CBAM Position vs ~1.37 benchmark | H₂ Cost at Green H₂ $4/kg |
|---|---|---|---|---|
| 0% (pure natural gas) | 0.90–1.20 | ~1.00–1.30 | At/near benchmark — zero or minimal CBAM | Not applicable |
| 30% H₂ blend | 0.68–0.90 | ~0.78–1.05 | Below benchmark — zero CBAM | ~$150/t DRI incremental H₂ cost |
| 70% H₂ blend | 0.36–0.48 | ~0.46–0.60 | Well below benchmark — zero CBAM + green taxonomy Tier 3 | ~$350/t DRI incremental H₂ cost |
| 100% H₂ (green) | 0.02–0.05 | ~0.10–0.17 | Near-zero CBAM — green taxonomy Tier 4 | ~$500/t DRI incremental H₂ cost at $4/kg H₂ |
The table reveals that the economics of hydrogen blending are not all-or-nothing. A natural gas DRI plant running at 30 percent hydrogen blend reduces its Scope 1 intensity to approximately 0.78 to 1.05 tCO₂/t — well below the EU CBAM benchmark and therefore carrying zero CBAM obligation — at an incremental hydrogen cost of approximately $150/t of DRI produced. At $4/kg green hydrogen and a DRI hydrogen requirement of approximately 37.5 kg per tonne of DRI for the 30 percent blend increment, this represents a cost of approximately $150/t DRI — or approximately Rs 12,600/t DRI at current exchange rates. For a DRI-EAF plant where the DRI input cost is approximately Rs 25,000 to 35,000 per tonne, adding Rs 12,600 in hydrogen cost to eliminate the CBAM obligation of approximately €62/t (approximately Rs 5,500/t at current EUR-INR) on EU-bound steel is not commercially justified at current CBAM prices — the H₂ cost exceeds the CBAM saving at low blend ratios. But at 70 percent hydrogen blend, the CBAM saving (zero obligation on steel that would otherwise carry €62–165/t) increasingly dominates the incremental hydrogen cost as EU ETS prices rise toward 2030.
Why JSPL’s Angul DRI complex is India’s most strategically positioned steel asset for the 2030s. JSPL’s Angul plant in Odisha operates India’s largest natural gas DRI capacity in an integrated configuration with electric arc furnaces producing structural steel, rails, and plates. The site has several structural advantages that make it the most likely location for India’s first commercial hydrogen DRI operation. Odisha’s 50 percent CSS exemption for open access renewable electricity reduces the cost of the renewable power needed for green hydrogen electrolysis. The Angul site is on the eastern grid which will receive progressively lower-emission electricity as Odisha’s RE capacity builds. JSPL has publicly stated its intent to introduce hydrogen at Angul under the SIGHT programme. And unlike BF-BOF integrated plants that face the complexity of maintaining a continuous blast furnace while introducing new technology, JSPL’s DRI shaft furnaces can be hydrogen-transitioned campaign by campaign without production interruption. Angul is India’s template for the hydrogen DRI transition — what happens there in 2026 to 2030 will define the trajectory for the broader industry.
Frequently Asked Questions
Why is coal-based DRI not considered a decarbonisation pathway for India’s steel sector?
Coal-based DRI (produced in rotary kilns using non-coking coal) has a Scope 1 emission intensity of approximately 2.5 to 3.0 tCO₂/t of DRI produced — approximately the same as India’s blast furnace route at the iron ore reduction step. When this coal-DRI is used in an EAF to make crude steel, the total Scope 1 intensity of the crude steel is approximately 2.0 to 2.5 tCO₂/t — similar to BF-BOF and above the EU CBAM benchmark. Coal-based DRI does not solve the CBAM problem; it replicates it. Only natural gas DRI or hydrogen DRI produces iron with the low emission intensity that enables steel production below the CBAM benchmark. India’s coal-based DRI advantage is a production volume asset — it is not a decarbonisation asset.
What is the capital cost of converting a natural gas DRI plant to hydrogen DRI?
The capital cost of hydrogen-enabling a natural gas Midrex or Energiron shaft furnace is primarily the electrolyser capacity and hydrogen compression/storage infrastructure — not the reactor itself. For a 1 MTPA DRI plant transitioning to 30 percent hydrogen blend, the electrolyser capacity required is approximately 50 to 70 MW (depending on operating hours and hydrogen storage), with a capital cost of approximately Rs 300 to 500 crore at current electrolyser prices. For 70 percent hydrogen blend, the requirement rises to approximately 120 to 160 MW and Rs 700 to 1,200 crore. For 100 percent hydrogen, approximately 200 to 250 MW and Rs 1,200 to 2,000 crore. These figures decline significantly as electrolyser costs fall — the NGHM targets a 5× reduction in electrolyser manufacturing cost through the SIGHT PLI programme by 2030.
Can India’s coal-based DRI plants be converted to natural gas DRI?
No — not economically. Coal-based rotary kiln DRI uses a fundamentally different reactor technology from shaft furnace natural gas DRI. A rotary kiln cannot be retrofitted to use natural gas or hydrogen as the reductant. Converting from coal-DRI to gas-DRI requires replacing the entire DRI plant — not modifying the existing one. Given that coal-DRI plants in India have asset lives of 15 to 25 years, the economic case for full plant replacement depends on the CBAM cost trajectory, CCTS GEI target stringency, and the differential in operating cost between coal-DRI-EAF steel and natural gas-DRI-EAF steel at current gas prices. For plants approaching the end of their operating lives, replacement with natural gas DRI is the commercially rational choice. For plants with 10 to 15 years of remaining life, the decision requires a full NPV analysis against the specific asset’s cost structure.
Sources
- Midrex Technologies — Midrex Process technology overview — natural gas and hydrogen DRI configurations
- Tenova HYL/Energiron — Energiron ZR process — zero reformer hydrogen DRI technology
- worldsteel — Steel statistical yearbook 2025 — DRI production by country and technology
- Mission Innovation — Green hydrogen steel cost curves — global analysis 2025
- JSPL — JSPL Annual Report FY2025 — Angul DRI-EAF capacity and hydrogen plans