Green iron: a long-term option for Central Africa, gated by ore, power and gas

6.1 Why ironmaking is where the carbon is

In the blast-furnace route, almost all of steel’s CO₂ comes from turning ore into iron; converting iron into steel and rolling it add comparatively little. In an electric works that buys DRI, the same carbon appears upstream, in the supplier’s shaft furnace. Chapter 4 showed that the imported iron units are the largest block in RC-1’s footprint. Lowering the carbon content of iron, wherever it is made, is therefore the central task of steel decarbonisation.

Two technologies dominate the pipeline. Gas-based direct reduction, using the MIDREX or Energiron processes, already produces about two-thirds of the world’s DRI; the rest is made mostly in coal-fired rotary kilns in India [S13]. The same shaft furnaces can be designed to run on a rising share of hydrogen, up to 100%, because the reducing gas they use from natural gas is already a mixture of hydrogen and carbon monoxide [S15][S17]. Hydrogen reduces iron oxide to iron and water vapour instead of CO₂.

6.2 Gas first, then hydrogen

Figure 6.1 places published intensities for ore-based routes on one scale. The worldsteel average for gas-based DRI-EAF is 1.47 t CO₂ per tonne [S01]. Energiron reports that its process with natural gas emits about 53% less than the blast-furnace route and, with 100% hydrogen, about 86% less [S15]; applied to the worldsteel blast-furnace average, those percentages correspond to about 1.10 t and 0.33 t per tonne (derived). The Saarstahl and Dillinger project in Germany expects its gas-based DRI-EAF route to emit 1.098 t CO₂e per tonne and, with green hydrogen and green power, 0.339 t [S18].

Source: worldsteel [S01]; EC Innovation Centre for Industrial Transformation, Energiron and POWER4STEEL pages [S15][S18]; IEA near-zero threshold [S06]; WP06 model [S90]. Energiron values derived by applying the stated percentages to the worldsteel blast-furnace average.

The energy and material requirements are well documented:

• Natural gas. A modern shaft furnace uses about 9.2 to 10 GJ of natural gas per tonne of DRI; Egypt’s Suez Steel reported a sustained 9.2 GJ per tonne in 2026 [S16][S15]. A 1 Mt/yr DRI module would therefore need about 9.2 to 10 PJ of gas a year, about 11% to 12% of Cameroon’s 2025 gas production of 75.5 billion cubic feet (derived) [S83].
• Hydrogen. Full hydrogen reduction needs about 54 kg of hydrogen per tonne of DRI [S17]. At electrolyser efficiencies of about 45 to 52 MWh per tonne of hydrogen [S05], that is about 2.4 to 2.8 MWh of electricity per tonne of DRI for the hydrogen alone (derived).
• Ore. Both gas and hydrogen shaft furnaces need DR-grade pellets: high in iron and low in silica and alumina, because unlike a blast furnace the shaft furnace does not remove gangue as slag before melting; the gangue goes into the electric furnace and raises its energy use and slag volume.

The cost of the hydrogen route depends above all on electricity. The IEA estimates that hydrogen-based DRI needs power below about US$35 per MWh to compete with gas-based DRI fitted with carbon capture [S05]. The Energy Transitions Commission’s earlier analysis found that electricity below about US$40 per MWh is needed for hydrogen-based DRI to beat carbon capture on a new blast furnace, and that full decarbonisation of steel costs about US$60 per tonne of CO₂, or about US$115 per tonne of steel, falling to about US$25 per tonne of CO₂ and US$50 per tonne of steel where very cheap renewable electricity is available [S09].

6.3 The ore-quality question

DR-grade iron ore is scarce. The Institute for Energy Economics and Financial Analysis (IEEFA) noted in 2022 that DR-grade ore ideally contains 67% iron or more, and that only about 3% of seaborne iron ore trade had an iron content above 66% [S75]. Agora Industry warned in 2023 that, unless urgent action is taken, demand for DR-grade ore will significantly outstrip supply by 2030 [S11]. IEEFA’s 2026 assessment expects the high-grade market to grow, as new mines and beneficiation plants come on stream [S76], but the scarcity is a structural feature of the transition: the iron ore most of the world mines today was chosen for blast furnaces, which tolerate more gangue.

Cameroon is a significant prospective ore producer. Global Energy Monitor counts 64 Mtpa of iron-ore mine capacity in development in Cameroon, about 9% of the world total [S14]. The Mbalam deposit, whose exploitation permit is held by Cameroon Steel’s sister company Cameroon Mining Company, was reported at the foundation-stone ceremony of the Kribi steel complex as holding more than 2 billion tonnes of ore, including 517 Mt of direct-shipping ore above 62.3% iron [S72]; the reserve statement published under the JORC Code in 2015 gives 62.2% iron for the same 517 Mt (White paper 03, Chapter 4). That is a respectable grade for blast-furnace and sinter feed. It is not DR grade. The much larger lower-grade banded iron formations (itabirites) that make up most of such resources would have to be ground, concentrated and pelletised to reach DR specification.

Table 6.1 Iron-ore quality and the direct-reduction route

Source: as listed. Concentration processes are generic descriptions, not a project design.

This is the single most important unknown in the green-iron option. If Cameroonian ore can be upgraded economically to DR-grade concentrate and pelletised, the country could one day supply its own steelworks and export iron units with a low carbon content. If it cannot, a Cameroonian direct-reduction module would depend on imported DR-grade pellets, competing for a scarce product. Chapter 10 recommends an early concentrate and pelletising study to settle the question before land, gas or power are committed to the reserve module.

6.4 Africa’s direct-reduced iron is a North African story so far

Africa produced about 16 Mt of DRI in 2025, most of it in North Africa: Algeria 6.70 Mt, Egypt 6.06 Mt and Libya 1.75 Mt on Midrex plant statistics, all gas-based [S13][S03]. On the same statistics Sub-Saharan Africa produced 0.09 Mt, and its gas-based plants, including Nigeria’s 1.02 Mt/yr Delta Steel and South Africa’s 0.80 Mt/yr Saldanha unit, were idle at the end of 2025 [S13]. worldsteel, whose figures include estimates for plants outside that survey, puts output in Uganda, Kenya and Tanzania at about 2.7 Mt [S03]; the two series differ in coverage, and neither shows an operating gas-based plant south of the Sahara. Figure 6.2 shows the contrast.

Source: Midrex Technologies, 2025 World Direct Reduction Statistics [S13]; East African estimate from worldsteel, World Steel in Figures 2026 [S03].

The first African green-iron plant is in Namibia. The HyIron Oshivela project, inaugurated in April 2025 with European support, combines solar power, batteries and an electrolyser to make DRI with hydrogen in a pilot of about 15,000 t a year, with plans to scale up in stages [S77][S78]. It is small, but it shows that the technology can be deployed on the continent and that European partners are prepared to co-finance it.

6.5 What the studies say about Africa’s green-iron opportunity

A body of recent analysis argues that ironmaking will partly relocate to places where ore and cheap clean energy coincide. Table 6.2 summarises the studies most relevant to Central Africa.

Table 6.2 Selected studies on green iron and the steel transition

Source: as listed.

Read together, the studies support three conclusions for Central Africa. The opportunity is real: importers will pay for iron with a low carbon content, and they will pay more as carbon prices and border measures bite. The winners will be locations that combine DR-grade ore, low-cost firm clean electricity and port access, not merely one of the three. And the timeline is long: most studies place large-scale green iron trade in the 2030s and 2040s.

6.6 How much power would hydrogen need in Cameroon?

Figure 6.3 sets the electricity needed for hydrogen-based reduction against Cameroon’s power system. Supplying RC-1’s own iron units at full build-out, about 0.36 Mt of DRI a year, with hydrogen would take about 0.9 to 1.0 TWh of electricity a year for electrolysis alone. A full-size 1 Mt/yr module would take about 2.4 to 2.8 TWh. For comparison, Nachtigal, Cameroon’s largest hydro plant, injected 3.6 TWh in the twelve months to May 2026 [S52], and the whole country generated 8.12 TWh in 2025 [S50].

Source: hydrogen requirement [S17]; electrolyser efficiency [S05]; Nachtigal output [S52]; national generation [S50]; hydro potential [S53]. Derived by Cameroon Steel (Annex A).

The resource exists: Cameroon’s hydro potential is estimated at about 115 TWh a year, of which only about 4% is developed [S53]. The constraint is cost and firmness. At the purchase price of about 43.93 FCFA per kWh reported for the Memve’ele plant [S50][S103], about US$73 per MWh at a planning rate of 600 FCFA to the dollar (derived), new hydro is well above the US$35 to US$40 per MWh that the IEA and the ETC identify as competitive for hydrogen-based iron [S05][S09]. Older hydro sold under legacy contracts is cheaper, but its output is committed. Hydrogen-based iron in Cameroon would therefore need either very low-cost new hydro, a carbon price or premium that closes the gap, or both.

6.7 Gas: the bridge whose availability has just changed

A gas-based direct-reduction module, designed to accept hydrogen later, is the natural first step for ore-based iron in Central Africa, as it was in North Africa. Cameroon’s gas is produced mainly from the Sanaga Sud field near Kribi. In 2025, about 95% of national gas output was sold as feed to the floating liquefaction vessel Hilli Episeyo [S83]; the vessel’s charter ended and it left Cameroon in July 2026 [S84]. That frees gas in the near term, but the field is mature and its remaining reserves are not publicly certified, and the larger Yoyo-Yolanda resource has no final investment decision [S85]. A direct-reduction module would need a long-term supply contract backed by a reserve audit before it could be designed.

6.8 A stepwise, gated route

Figure 6.4 sets out how RC-1’s iron units could evolve. Each step is optional and conditional; none is a commitment of this paper.

Source: Cameroon Steel reference configuration RC-1 (planning estimate), reserve module [S90]; analysis in this chapter.

1. From the first heat (targeted for the second half of 2030): imported scrap and certified DRI/HBI. Phase 1 melts scrap and buys DRI or HBI on the international market, with a verified carbon intensity and a contractual ceiling for each cargo. This is where the largest near-term savings are (Chapter 4).
2. Later, after the main phases: a domestic gas-based module. If DR-grade concentrate and a gas contract are secured, a shaft furnace sized to RC-1’s needs (about 0.36 Mt of DRI a year at 1 Mtpa) or larger would replace imports. The RC-1 master plan reserves land for a direct-reduction module and pellet yard. On gas, its emissions would move from upstream into Cameroon Steel’s own Scope 1, at an intensity similar to the imported DRI it replaces; the gain is in value added and supply security, not yet in carbon.
3. As hydro grows: hydrogen blending. Shaft furnaces can accept a rising share of hydrogen in the reducing gas. Each step would require electrolysers and firm power, and would lower the module’s emissions in proportion.
4. Long term: hydrogen DRI and green HBI. At high hydrogen shares, the module could make iron at a few tenths of a tonne of CO₂ per tonne, for RC-1’s own furnaces and for export as HBI into markets where CBAM and buyers reward low carbon. Under CBAM, DRI and HBI are covered goods, priced on their direct emissions from the outset (Chapter 5).

Table 6.3 Evidence needed before each step

Source: Cameroon Steel analysis. Timings are indicative.

The KPIZ development plan already lists steelmaking linked to mineral exports among the zone’s clusters [S74], and Cameroon’s 2023 Mining Code provides for the local transformation of part of mine output [S86]. A stepwise green-iron route would align with both, while keeping each investment conditional on the evidence that justifies it.