方法与假设

A.1 Evidence statuses

Every figure in this paper carries one of four statuses, shown as a chip on each exhibit:

• Sourced: read from a published source listed in Annex C.
• Derived: Cameroon Steel’s arithmetic on sourced or planned inputs, shown in this annex.
• Assumed: a stated planning assumption, with a range.
• Illustrative: a scenario or a picture of how something works, not a forecast.

Three further words qualify RC-1 values only, never a sourced figure: planned (a value of the reference configuration), indicative (a later phase or a value still to be engineered) and target (a schedule date).

Project figures come from the Cameroon Steel reference configuration RC-1 (planning estimate), edition of 10 October 2026, as revised on that date (RC-1.1) [S07]. They are planned or indicative values derived from published benchmarks and will be replaced by supplier guarantees at front-end engineering. They are not commitments.

A.2 Conventions and conversion factors

• Currency. The CFA franc (FCFA, XAF) is pegged to the euro at 655.957 FCFA per euro. The US dollar rate floats; this paper uses a planning rate of 600 FCFA per US dollar (range 560 to 650) [S07], except where a source states its own rate. SNH’s 2025 accounts use quarterly rates from 624.9 to 561.0 FCFA per US dollar [S05].
• Gas volumes and energy. 1 Mscf (thousand standard cubic feet) is taken as 1.037 MMBtu, or about 1.094 GJ on a higher-heating-value basis; 1 bcf is therefore about 1.094 PJ. 1 m3 is 35.315 standard cubic feet, so 1 Mscf is 28.317 m3. With these factors, 9.2 to 10 PJ is 8.4 to 9.1 bcf [S39][S41].
• Electricity. 1 MWh is 3.6 GJ of final energy. worldsteel counts each MWh as about 9.8 GJ of primary energy [S35].
• Tonnes. Finished products are bars, wire rod and sections; liquid steel is steel tapped from the furnace; the metallic charge is scrap plus DRI or HBI. Nameplate output is the design capacity; expected sustained output is the planning range for a mature year (270,000 to 300,000 t in Phase 1).
• Operating hours. Average loads are annual energy divided by 8,000 operating hours a year, as in RC-1 [S07].

A.3 Assumptions and ranges

Table A.1 Assumptions used in this paper, with ranges and status

Source: as listed.

A.4 Derivations

RC-1 balances. Liquid steel equals finished products divided by the casting and rolling yield (0.94); the metallic charge equals liquid steel divided by the metallic yield (0.88); the DRI or HBI quantity equals the metallic charge times 30%. Electricity equals liquid steel times (450 + 70) kWh/t, plus 300 kWh/t on the 300,000 t of the Phase 1 mills, plus 110 kWh/t on all finished products. For Phase 1 this gives 319,149 t of liquid steel and 288,957 MWh; for the full works 1,063,830 t and 753,191 MWh [S07]. At the upper planning value the furnace uses 40 kWh more per tonne of liquid steel: 301,723 MWh in Phase 1, 442,872 MWh for Phases 1 and 2 and 795,745 MWh at full build-out, or 37.7, 55.4 and 99.5 MW on 8,000 hours (derived). Reheating gas is 1.3 GJ/t on the products of Phases 2 and 3: 260,000 GJ for 200,000 t and 910,000 GJ for 700,000 t.

Electricity cost per tonne (Table 1.2). Cost per tonne equals the electricity intensity (0.963 MWh/t in Phase 1; 0.753 MWh/t at full build-out) times the price in FCFA/kWh times 1,000, converted at 600 FCFA per US dollar. For example, 0.963 x 43.7 x 1,000 = 42,091 FCFA/t, or US$70.2/t. At the upper planning value, 1.006 MWh/t, every cost is 4.4% higher.

Medium-voltage all-in price (Figures 3.1 and 3.2). All-in price = (monthly fixed charge per kW / hours of use at subscribed power + energy charge) x 1.1 cubed, where 1.1 cubed (1.331) applies the three annual increases of 10% for the 3 to 10 MW bands in 2024, 2025 and 2026 [S03]. At 650 hours a month in the 9 to 10 MW band: (15,500 / 650 + 9) x 1.331 = 43.7 FCFA/kWh. For RC-1 Phase 1: 288,957 MWh / (55 MVA x 0.95) = 5,530 hours a year, or 461 hours a month, giving 56.7 FCFA/kWh. At 301,723 MWh: 5,775 hours a year, or 481 a month, giving 54.8 FCFA/kWh, 28% above the flat-load 42.9.

Legacy high-voltage price. 17.80 bn FCFA / 969.03 GWh = 18.4 FCFA/kWh [S01].

Transmission charge. For a 100 MW load at an 80% load factor (700,800 MWh a year): (16.18 m FCFA x 100 + 0.41 FCFA x 700.8 m kWh + 4.48 m FCFA) / 700.8 m kWh = 2.7 FCFA/kWh [S53].

Kribi gas plant. Capacity factor = 559.67 GWh / (216 MW x 8,760 h) = 29.6%. Gas use = 4.92 bcf / 559.67 GWh = 8.79 Mscf per MWh, or about 9.6 GJ per MWh, an electrical efficiency of about 37%. At 80% capacity factor: 216 x 0.8 x 8,760 = 1,514 GWh, needing 13.3 bcf; at 330 MW, 20.3 bcf. Fuel cost per kWh at US$3.2/Mscf: 8.79 x 3.2 / 1,000 = US$0.028, or about 17 FCFA; at US$5.6/Mscf, about 30 FCFA. Emissions: 9.6 GJ/MWh x 0.0561 = 0.54 t CO₂/MWh [S05][S01].

Combustion-only grid intensity, 2025 (Chapter 8). About 74 g/kWh, an estimate taken from White paper 06 (Chapter 3 and Annex A), so that the series prints one value with one derivation. The emission rate of gas and oil generation implied by the 2024 data, about 771 g/kWh, is applied to the gas and oil generation that the regulator reports for 2025 (559.7 + 153.9 + 66.7 = 780.3 GWh) [S01], which gives about 602 kt of CO₂; divided by total generation of 8,119.9 GWh, this is about 74 g/kWh. Hydro and solar are counted at zero on this basis. The difference from the life-cycle average of 226 g/kWh for 2024 [S10] reflects both the basis (combustion versus life cycle) and the year and data source (Chapter 2).

Gas for direct reduction (Figure 7.1). Gas in bcf = module capacity in Mt x GJ per tonne / 1.094. For 1 Mt: 9.2 / 1.094 = 8.4 bcf; 10 / 1.094 = 9.1 bcf; 23 to 25 MMscf a day over 365 days. Over twenty years: 168 to 183 bcf. Gas cost per tonne of DRI = gas price x GJ per tonne / 1.094; at US$5.6/Mscf: 47 to 51 US$/t.

Gas balance (Figure 6.1). Candidate domestic uses: the Kribi plant at its 2025 dispatch (4.92 bcf), at an 80% capacity factor (13.3 bcf) and extended to 330 MW (20.3 bcf); the industrial buyer at twice its half-year purchase (6.2 bcf); RC-1 reheating at full build-out (910,000 GJ / 1.094 = 0.83 bcf); a 1 Mtpa DRI module (8.4 to 9.1 bcf). Without DRI: 13.3 + 6.2 + 0.8 = 20.3 bcf. With the plant at 330 MW and DRI: 20.3 + 6.2 + 0.8 + 9.1 = 36.5 bcf.

FLNG cumulative feed (Chapter 6). Operation from June 2018 to July 2026 is about eight years [S88][S16]. At 60 to 72 bcf a year, the cumulative feed would be about 490 to 580 bcf, the same order as the 500 bcf allocation [S84]. This is an approximation to be replaced by SNH’s production records.

Special petroleum tax. 70 FCFA/m3 x 28.317 m3/Mscf = 1,982 FCFA/Mscf, or US$3.2 at 625 FCFA per US dollar and US$3.5 at 561 [S87][S05].

Flicker screening (Figure 4.3). Pst99 = Kst x SscF / SscPCC is a simplified screening relation used by this paper, not a calculation from a standard; the Kst range of 48 to 85 is the UIE’s, as cited in [S12]. SscF is taken at about twice the rating of a transformer of the 30 to 33 MVA class. The short-circuit power needed at the PCC is SscF multiplied by Kst and divided by the planning level of 0.8: about 4,000 MVA at Kst 48 and about 7,000 MVA at Kst 85. With an SVC halving flicker [S12]: about 2,000 to 3,500 MVA. Results are given to one significant figure; Figure 4.3 and its table in Annex D are drawn from these rounded results. Several equal furnaces combine by a cubic law [S13]: two furnaces give 2 to the power one-third, about 1.3, times the flicker of one.

30 kV fault level. A transformer’s contribution to a fault on its secondary side is approximately its rating divided by its per-unit impedance. Three 60 MVA transformers at 12% give 3 x 60 / 0.12 = 1,500 MVA; at 18%, 1,000 MVA. A finite 225 kV source lowers these values further.

Solar (Chapter 8). PVGIS v5.3 PVcalc for 2.94 N, 9.91 E, crystalline silicon, 1 kWp, 14% system losses, optimal slope (6 degrees), radiation database PVGIS-SARAH3 for 2005 to 2023: 1,334.7 kWh per kWp a year [S19]. Capacity factor = 1,334.7 / 8,760 = 15.2%. A 50 MWp array: 50 x 1,334.7 = 66.7 GWh a year, 23% of Phase 1’s 289 GWh and 22% of 302 GWh. Daily profiles use PVGIS DRcalc average irradiance by hour for January and July, shifted from UTC to West Africa Time, times 50 MW per 1,000 W/m2 times a performance ratio of 0.80.

Scope 2 and the near-zero threshold. Scope 2 per tonne = 0.963 MWh/t x grid factor. The IEA near-zero threshold is 0.40 - 0.35 x scrap share t CO₂e per tonne [S20]; at a 70% scrap share (253,868 t of scrap in 362,669 t of metallics in Phase 1 [S07]) it is 0.155 t.

Illustrative load profiles (Figures 4.1 and 9.2). Each heat follows a fixed sequence: bore-in (4 minutes, 20 MW mean), melting (16 minutes, 27 MW), recharge (3 minutes, off), bore-in (4 minutes, 20 MW), melting (12 minutes, 27 MW), refining (8 minutes, 24 MW) and tapping and turnaround (13 minutes, off), with random variation of 35% during bore-in, 14% during melting and 4% during refining (fixed random seed), and active power capped at 30 MW, about what a transformer of the 30 to 33 MVA class delivers with short-term overload. The mean energy per heat is about 18 MWh, or about 450 kWh per tonne on a heat of about 40 t, consistent with the RC-1 planning value. Steady loads are 11.25 MW for induction heating (300 kWh/t x 37.5 t/h), 4.13 MW for rolling (110 kWh/t x 37.5 t/h) and 1.3 MW of auxiliaries, plus a 4.5 MW ladle-furnace pulse for 20 minutes an hour. The profiles show the character of the load and are not forecasts.

Upper planning value for the furnace (Chapter 1). 450 kWh/t, read as an all-scrap value, plus 14.5 kWh/t for each 10 percentage points of DRI or HBI in the charge [S39]: 450 + 3 x 14.5 = 493.5 kWh/t at RC-1’s 30%, used as the upper planning value of about 490 kWh/t (as in White paper 03); 522.5 kWh/t at 50%.

Schedulable load and the cost of curtailment (Chapter 9). About 8,000 heats of about 40 t at nameplate need about 7,300 to 7,900 furnace hours at about 55 to 59 minutes tap to tap (450 to 490 kWh/t), out of the 8,760 hours in a year (White paper 03, Chapter 5 and Annex A). At the 7,000 to 7,700 operating hours that give the expected sustained output, the furnace is not scheduled to operate for the remaining 1,060 to 1,760 of the year’s 8,760 hours, about three to five hours a day. Beyond those hours, one hour of curtailment costs about one heat (about 40 t): 100 hours cost about 4,000 t of liquid steel, about 1.25% of 319,149 t. Moving 20 to 30 MW out of the peak equals 1.6% to 2.3% of the 2025 peak of 1,278 MW [S01].

Phase 1 metallics and port inbound (Chapter 7). Domestic scrap is planned at 30,000 t a year (0 to 60,000 t), bounded by the only quantified national study of scrap arising, 53,000 to 61,833 t a year in 2006 [S98]; the rest of the 253,868 t of scrap and the 108,801 t of DRI or HBI are imported, which with about 6% of consumables gives about 351,000 t a year of port inbound cargo at nameplate [S07].

Phase 1 electricity range (Chapter 9). Low case: 319,149 t x (347 + 50) kWh/t + 300,000 t x (150 + 70) kWh/t = 192.7 GWh. High case: 319,149 t x (500 + 100) + 300,000 t x (400 + 140) = 353.5 GWh.

A.5 Maps

The maps were drawn by Cameroon Steel from OpenStreetMap data (© OpenStreetMap contributors, Open Database Licence), extracted through the Overpass API on 24 July 2026 (coast, roads, land use around Kribi) and 10 October 2026 (power lines, substations and plants in southern Cameroon) [S60], and from Natural Earth country boundaries. OpenStreetMap is a volunteer dataset: it is not a complete or authoritative record of the network, and the 400 kV Nachtigal line, for example, was not mapped at the time of extraction. The route of the new 225 kV line from the Kribi gas plant to the port is drawn schematically between its published end points, and the port substation’s position is indicative. No site boundaries are shown.

A.6 Quality checks

Before publication, the text was checked for consistency between every figure quoted in the prose, the tables and the chart data; for the units, years and sources of every number; and for the absence of confidential or commercially sensitive information. Generated images are labelled "Illustrative view" and are not photographs of any project.